**UNITED STATES SECURITIES AND EXCHANGECOMMISSION**

**WASHINGTON,D.C. 20549**

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**Form 10-K**

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| x                                                     |   | **ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d)  OF THE SECURITIES EXCHANGE ACT OF 1934**     |
|-------------------------------------------------------|--------|------------------------------------------------------------------------------------------------|
|                                                  |   | ** **                                                                                     |
| **For the  fiscal year ended December 31, 2007** |   |
| ** **                                            |   | ** **                                                                                     |
| o                                                     |   | **TRANSITION REPORT PURSUANT TO SECTION 13 OR 15  (d) OF THE SECURITIES EXCHANGE ACT OF 1934** |
|                                                       |        |                                                                                                |  |

 

**Commission file number:  000-51719**

 

**LINN ENERGY, LLC**

(Exact name of registrant as specified in itscharter)

 

| **Delaware**                                                           | ** ** | **65-1177591**                        |
|------------------------------------------------------------------------|------------|---------------------------------------|
| (State or other jurisdiction of

 incorporation  or organization) |       | (I.R.S. Employer

Identification No.) |
|                                                                   |       |                                  |
| **600 Travis Street, Suite 5100**                                 | ** ** | ** **                            |
| **Houston, Texas**                                                     | ** ** | **77002**                             |
| (Address of principal executive offices)                               |       | (Zip Code)                            |

 

Registrant’s telephone number, including area code

**(281) 840-4000**

 

Securities registered pursuant to Section 12(b) of the Act:

** **

| **Title of each class**                                 | ** ** | **Name of each exchange on which  registered** |
|---------------------------------------------------------|------------|------------------------------------------------|
| Units Representing Limited Liability Company  Interests |       | The NASDAQ Stock Market LLC                    |

 

Securities registered pursuant to Section 12(g) of the Act:

**None**

 

Indicate by check mark if the registrant is awell-known seasoned issuer, as defined in Rule 405 of the Securities Act.Yes         x           No           o

 

Indicate by check mark if the registrant is notrequired to file reports pursuant to Section 13 or Section 15(d) ofthe Exchange Act.Yes         o            No           x

 

Indicate by check mark whether registrant (1) has filed allreports required to be filed by Section 13 or 15(d) of the SecuritiesExchange Act of 1934 during the preceding 12 months (or for such shorterperiod that the registrant was required to file such reports), and (2) hasbeen subject to such filing requirements for the past 90 days.              Yes         x           No           o

 

Indicate by check mark if disclosure of delinquent filers pursuant toItem 405 of Regulation S-K is not contained herein, and will not becontained, to the best of registrant’s knowledge, in definitive proxy orinformation statements incorporated by reference in Part III of this Form 10-Kor any amendment to this Form 10-K.           o

 

Indicate by check mark whether the registrant is a large acceleratedfiler, an accelerated filer, a non-accelerated filer, or a smaller reportingcompany. See the definitions of “large accelerated filer,” “accelerated filer”and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large acceleratedfiler  x     Acceleratedfiler  o     Non-acceleratedfiler  o     Smaller ReportingCompany  o

 

Indicate by check-mark whether the registrant is ashell company (as defined in Rule 12b-2 of the Act).Yes         o            No           x

 

The aggregate market value of voting and non-voting common equity heldby non-affiliates of the registrant was approximately $1,974,449,832 on June 29,2007, based on $32.91 per unit, the last reported sales price of the units onThe NASDAQ Global Market on such date.

 

As of January 31, 2008, there were 114,632,034 units outstanding.

 

**Documents Incorporated By Reference:**

 

Certain information called for inItems 10, 11, 12, 13 and 14 of Part III are incorporated by referencefrom the registrant’s definitive proxy statement for the annual meeting ofunitholders to be held on May 29, 2008.

 

 

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**TABLE OF CONTENTS**

 
| ** ** | ** **                                                                                                          |       | **Page** |
|------------|---------------------------------------------------------------------------------------------------------------------|------------|----------|
| ** ** | **Glossary of Terms**                                                                                               |       | ii       |
|       |                                                                                                                |       |     |
| ** ** | **Part I**                                                                                                     | ** ** |     |
| ** ** | ** **                                                                                                          | ** ** |     |
| Item 1.    | Business and Properties                                                                                             |       | 1        |
| Item 1A.   | Risk  Factors                                                                                                       |       | 17       |
| Item 1B.   | Unresolved  Staff Comments                                                                                          |       | 26       |
| Item 2.    | Properties                                                                                                          |       | 27       |
| Item 3.    | Legal Proceedings                                                                                                   |       | 27       |
| Item 4.    | Submission  of Matters to a Vote of Security Holders                                                                |       | 27       |
|       |                                                                                                                |       |     |
| ** ** | **Part II**                                                                                                    | ** ** |     |
| ** ** | ** **                                                                                                          | ** ** |     |
| Item 5.    | Market for  Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases  of Equity Securities |       | 28       |
| Item 6.    | Selected Financial  Data                                                                                            |       | 30       |
| Item 7.    | Management’s  Discussion and Analysis of Financial Condition and Results of Operation                          |       | 31       |
| Item 7A.   | Quantitative  and Qualitative Disclosures About Market Risk                                                         |       | 50       |
| Item 8.    | Financial  Statements and Supplementary Data                                                                        |       | 52       |
| Item 9.    | Changes in  and Disagreements With Accountants on Accounting and Financial Disclosure                               |       | 91       |
| Item 9A.   | Controls and  Procedures                                                                                            |       | 91       |
| Item 9B.   | Other Information                                                                                                   |       | 91       |
|       |                                                                                                                |       |     |
| ** ** | **Part III**                                                                                                   | ** ** |     |
| ** ** | ** **                                                                                                          | ** ** |     |
| Item 10.   | Directors,  Executive Officers and Corporate Governance                                                             |       | 92       |
| Item 11.   | Executive  Compensation                                                                                             |       | 92       |
| Item 12.   | Security  Ownership of Certain Beneficial Owners and Management and Related Stockholder  Matters                    |       | 92       |
| Item 13.   | Certain  Relationships and Related Transactions, and Director Independence                                          |       | 92       |
| Item 14.   | Principal  Accounting Fees and Services                                                                             |       | 92       |
|       |                                                                                                                |       |     |
| ** ** | **Part IV**                                                                                                    | ** ** |     |
| ** ** | ** **                                                                                                          | ** ** |     |
| Item 15.   | Exhibits and  Financial Statement Schedules                                                                         |       | 93       |
|       |                                                                                                                |       |     |
| ** ** | **Signatures**                                                                                                      |       | 94       |

 

i

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**GLOSSARY OF TERMS**

 

As commonly usedin the oil and gas industry and as used in this Annual Report on Form 10-K,the following terms have the following meanings:

 

*ARO. *Asset retirementobligation.

 

*Bbl. *One stock tank barrel or 42 United States gallonsliquid volume.

 

*Bcf.* One billion cubic feet.

 

*Bcfe.* One billion cubic feet equivalent, determined using a ratio of six Mcfof gas to one Bbl of oil, condensate or natural gas liquids.

 

*Btu.* One British thermal unit, which is the heat required to raise thetemperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

 

*Developmentwell.*  A well drilled within the proved area of anoil or gas reservoir to the depth of a stratigraphic horizon known to beproductive.

 

*Dth.* One decatherm, equivalent to one million British thermal units.

 

*Developedacres.*  Acres spaced or assigned to productive wells.

 

*Dryhole* or*well.* A well found to be incapable of producing hydrocarbons in sufficientquantities such that proceeds from the sale of such production would exceedproduction expenses and taxes.

 

*Field.* An area consisting of a single reservoir or multiple reservoirs allgrouped on or related to the same individual geological structural featureand/or stratigraphic condition.

 

*FERC. *Federal Energy Regulatory Commission.

 

*Grossacres* or*gross wells.*  The total acres or wells, as the case may be,in which a working interest is owned.

 

*LIBOR.*  London Interbank Offered Rate.

 

*MBbls.* One thousand barrels of oil or other liquid hydrocarbons.

 

*Mcf.* One thousand cubic feet.

 

*Mcfe.* One thousand cubic feet equivalent, determined using the ratio of sixMcf of gas to one Bbl of oil, condensate or natural gas liquids.

 

*MMBbls.* One million barrels of oil or other liquid hydrocarbons.

 

*MMboe.* One million barrels of oil equivalent determined using a ratio of sixMcf of gas to one Bbl of oil, condensate or natural gas liquids.

 

*MMBtu.* One million British thermal units.

 

*MMcf.* One million cubic feet.

 

*MMcfe.* One million cubic feet equivalent, determined using a ratio of six Mcfof gas to one Bbl of oil, condensate or natural gas liquids.

 

*MMcfe/d.* One MMcfe per day.

 

*MMMBtu.* One billion British thermal units.

 

*Netacres* or*net wells.*  The sum of the fractional working interestsowned in gross acres or gross wells, as the case may be.

 

*NGL.* Natural gas liquids, which are the hydrocarbon liquids contained withingas.

 

*NYMEX.* The New York Mercantile Exchange.

 

*Oil.* Crude oil, condensate and natural gas liquids.

 

*PEPL.* Panhandle Eastern Pipeline.

 

ii

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*Productivewell.*  A well that is found to be capable ofproducing hydrocarbons in sufficient quantities such that proceeds from thesale of such production exceeds production expenses and taxes.

 

*Proveddeveloped reserves.*  Reserves that can be expected to be recoveredthrough existing wells with existing equipment and operating methods.  Additional oil and gas expected to be obtainedthrough the application of fluid injection or other improved recoverytechniques for supplementing the natural forces and mechanisms of primaryrecovery are included in “proved developed reserves” only after testing by apilot project or after the operation of an installed program has confirmedthrough production response that increased recovery will be achieved.

 

*Provedreserves.*  Proved oil and gas reserves are the estimatedquantities of gas, natural gas liquids and oil which geological and engineeringdata demonstrate with reasonable certainty to be recoverable in future yearsfrom known reservoirs under existing economic and operating conditions, i.e., prices and costs as of thedate the estimate is made.  Pricesinclude consideration of changes in existing prices provided only bycontractual arrangements, but not on escalations based on futureconditions.  The definition of provedreserves is in accordance with the Securities and Exchange Commission’sdefinition set forth in Regulation S-X Rule 4-10(a) and its subsequent staff interpretations and guidance.

 

*Provedundeveloped drilling location.*  A site onwhich a development well can be drilled consistent with spacing rules forpurposes of recovering proved undeveloped reserves.

 

*Provedundeveloped reserves*or*PUDs. *Reserves that are expected to be recovered from new wells onundrilled acreage or from existing wells where a relatively major expenditureis required for recompletion.  Reserveson undrilled acreage are limited to those drilling units offsetting productiveunits that are reasonably certain of production when drilled.  Proved reserves for other undrilled units areclaimed only where it can be demonstrated with certainty that there iscontinuity of production from the existing productive formation.  Estimates for proved undeveloped reserves arenot attributed to any acreage for which an application of fluid injection orother improved recovery technique is contemplated, unless such techniques havebeen proved effective by actual tests in the area and in the same reservoir.

 

*Recompletion.* The completion for production of an existing wellbore in anotherformation from that which the well has been previously completed.

 

*Reservoir.*  Aporous and permeable underground formation containing a natural accumulation ofeconomically productive oil and/or gas that is confined by impermeable rock orwater barriers and is individual and separate from other reserves.

 

*Royaltyinterest.*  An interestthat entitles the owner of such interest to a share of the mineral productionfrom a property or to a share of the proceeds therefrom.  It does not contain the rights andobligations of operating the property and normally does not bear any of thecosts of exploration, development and operation of the property.

 

*SEC*.  Securities and Exchange Commission.

 

*StandardizedMeasure.*  Standardized Measure, or standardized measureof discounted future net cash flows relating to proved oil and gas reservequantities, is the present value of estimated future net revenues to begenerated from the production of proved reserves, determined in accordance withthe rules and regulations of the Securities and Exchange Commission (usingprices and costs in effect as of the date of estimation) without giving effectto non-property related expenses such as general and administrative expenses,debt service and future income tax expenses or to depreciation, depletion andamortization and discounted using an annual discount rate of 10%.  The Company’s Standardized Measure does notinclude future income tax expenses because the reserves are owned by itssubsidiaries, which are not subject to income taxes.

 

*Successfulwell.*  A well capable of producing oil, gas and/orNGL in commercial quantities.

 

*Undevelopedacreage.*  Lease acreage on which wells have not beendrilled or completed to a point that would permit the production of commercialquantities of oil and gas regardless of whether such acreage contains provedreserves.

 

*Unprovedresources.*  Resources that are considered less certain tobe recovered than proved reserves. Unproved resources may be further sub-classified to denote progressivelyincreasing uncertainty of recoverability.

 

*Workinginterest.*  The operating interest that gives the ownerthe right to drill, produce and conduct operating activities on the propertyand a share of production.

 

*Workover.* Maintenance on a producing well to restore or increase production.

 

iii

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**Part I**

 

**Item 1.    Business and Properties**

 

This Annual Report on Form 10-K contains forward-looking statementsbased on expectations, estimates and projections as of the date of thisfiling.  These statements by their natureare subject to risks, uncertainties and assumptions and are influenced byvarious factors.  As a consequence,actual results may differ materially from those expressed in theforward-looking statements.  For moreinformation see “Forward-Looking Statements” included at the end of thisItem 1. “Business and Properties” and see also Item 1A. “Risk Factors.”

 

**References**

 

When referring toLinn Energy, LLC (“Linn Energy” or the “Company”), the intent is to refer toLinn Energy and its consolidated subsidiaries as a whole or on an individualbasis, depending on the context in which the statements are made.

 

A reference to a “Note”herein refers to the accompanying Notes to Consolidated Financial Statementscontained in Part II. Item 8. “Financial Statements and SupplementaryData.”

 

**Overview**

 

Linn Energy is anindependent oil and gas company focused on the development and acquisition oflong life properties which complement its asset profile in producing basinswithin the United States.  Linn Energybegan operations in March 2003 and completed its initial public offering (“IPO”)in January 2006.

 

The Company’s oil,gas and NGL properties are currently located in three regions in the UnitedStates:

 

·                  Mid-Continent, which includes the core operating areasTexas Panhandle and Oklahoma;

·                  Appalachian Basin, which includes fields in West Virginia andPennsylvania; and

·                  Western, which includes the Brea Olinda Field of the Los Angeles Basinin California.

 

Proved reserves atDecember 31, 2007 were 1,616.1 Bcfe, of which approximately 64% were gas,20% were oil and 16% were NGL. Approximately 73% were classified as proved developed, with a totalStandardized Measure value of $3.46 billion. At December 31, 2007, the Company operated 5,638, or 77%, of its7,305 gross productive wells.  Averageproved reserves-to-production ratio, or average reserve life, is approximately22 years, based on the December 31, 2007 reserve report and annualizedproduction for the fourth quarter ended December 31, 2007.

 

In January 2008,the Company completed two acquisitions of oil and gas properties in theMid-Continent and Appalachian Basin regions. See “Recent Developments” below for additional details about theseacquisitions.  On a pro forma basis,including these two acquisitions, total proved reserves at December 31,2007 were 1,945.5 Bcfe, of which approximately 55% were gas, 32% were oil and13% were NGL.

 

The Company’sprimary goal is to provide stability and growth of distributions for thelong-term benefit of its unitholders. The following is a summary of the key elements of the Company’s businessstrategy that support this goal:

 

·                  acquire long life, high quality properties;

·                  efficiently operate and develop acquiredproperties; and

·                  capture cash flow margin through commodity price and interest rate hedging.

 

The Company’sbusiness strategy is discussed in more detail below.

 

1

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**Item 1.    Business and Properties - Continued**

 

**Strategy**

 

***Acquire Long Life, High Quality Properties***

 

The Company’sacquisition program targets oil and gas properties which offer high quality,long life production with predictable decline curves as well as lower-riskdevelopment opportunities.  The Companyevaluates acquisitions based on reserve base, decline curve, reserve life, fieldcash flow and costs of development and operations.

 

The followingprovides a summary of acquisitions of working and royalty interests the Companyhas completed from inception through the date of this report:

 
| **Year**   | ** ** | **# of  Acquisitions** | ** ** | **Gross  Wells**(1) | ** ** | **Operating Region**                         | ** ** | **Aggregate  Contract  Price** | ** ** |
|------------|------------|------------------------|------------|---------------------|------------|----------------------------------------------|------------|--------------------------------|------------|
| ** ** | ** ** | ** **             | ** ** | ** **          | ** ** | ** **                                   | ** ** | **(in millions)**              | ** ** |
|       |       |                   |       |                |       |                                         |       |                           |       |
| 2003       |       | 4                      |       | 498                 |       | Appalachian Basin                            |       | $                              | 52.0       |   |
| 2004       |       | 2                      |       | 698                 |       | Appalachian Basin                            |       | 25.9                           |       |
| 2005       |       | 3                      |       | 718                 |       | Appalachian Basin                            |       | 124.5                          |       |
| 2006       |       | 5                      |       | 1,430               |       | Mid-Continent, Appalachian Basin and Western |       | 451.7                          |       |
| 2007       |       | 8                      |       | 4,505               |       | Mid-Continent, Appalachian Basin and Western |       | 2,678.9                        |       |
| 2008       |       | 2                      |       | 2,450               |       | Mid-Continent and Appalachian Basin          |       | 566.9                          |       |
|       |       | 24                     |       | 10,299              |       |                                         |       | $                              | 3,899.9    |   |

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| (1) |   | Gross wells do  not include approximately 1,800 wells associated with royalty interest  acquisitions. |
|-----|--------|-------------------------------------------------------------------------------------------------------|

 

From inceptionthrough the date of this report, the Company has completed 24 acquisitions ofworking and royalty interests in oil and gas properties and related gatheringand pipeline assets.  Total acquiredproved reserves were approximately 1.9 Tcfe at an acquisition cost ofapproximately $2.11 per Mcfe.  SeeNote 2 for additional details about the Company’s acquisitions.

 

The Company finances acquisitions with a combination of proceeds fromthe issuance of its units, bank borrowings and cash flow from operations. During 2007, the Company completed three private placements of itsunits, with gross proceeds of $2.12 billion. During 2006, the Company completed one additional private placement,with gross proceeds of $305.0 million. See “Recent Developments” below and also Note 4 for additionaldetails about the Company’s private placement of units.

 

***Efficiently Operate and Develop Acquired Properties***

 

The Company hascentralized the operation of its acquired properties into defined operatingregions to minimize operating costs and maximize production and capitalefficiency.  The Company maintains alarge inventory of drilling and optimization projects within each region toachieve organic growth from its capital development program.

 

The Company seeksto be the operator of its properties so that it can develop drilling programsand optimization projects that not only replace production, but add valuethrough reserve and production growth and future operational synergies.  The Company’s development program is focusedon lower-risk, repeatable drilling opportunities to maintain and/or growlong-term cash flow.  Many of the Company’swells are completed in multiple producing zones with commingled production andlong economic lives.  The number, typesand location of wells the Company drills vary depending on its capital budget,the cost of each well, anticipated production and the estimated recoverablereserves attributable to each well.  Inaddition, the Company seeks to deliver attractive financial returns byleveraging its purchasing power, experienced workforce and scalableinfrastructure.  For 2008, the Companyestimates its total drilling and development capital expenditures will be between$250.0 million and $300.0 million.  Thisestimate is under continuous review and is subject to on-going adjustment.

 

2

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**Item 1.    Business and Properties - Continued**

 

***Capture Cash Flow Margin ThroughCommodity Price and Interest Rate Hedging***

 

The Company has derivative contracts in place covering a significantportion of its forecasted production volumes through 2012, or five years, tocapture cash flow margins and provide long-term cash flow predictability to paydistributions and manage its business. Currently, the Company utilizes swaps and puts to hedge oil and gasproduction and oil puts to hedge NGL production.  Swap contracts establish a fixed price andput options set a price floor with the potential for realized commodity priceupside beyond the hedge price floor.  For2008, the Company’s production is approximately 97% hedged.  As of February 22, 2008, puts represent25%, 27%, 36%, 40% and 16% of annual hedged volume for all commodities for theeach of the years ended December 31, 2008 through December 31, 2012.

 

In addition, the Company enters into interest ratehedges to minimize the effects of fluctuations in interest rates.  Currently, the Company utilizes LIBOR swapsto convert its borrowing rate on indebtedness under its credit facility from afloating to fixed rate.  As of February 1,2008, the Company has swapped LIBOR on approximately 61% of its outstandingdebt at a fixed rate of 4.20% for 2008 and 5.06% for 2009 and 2010.  For additional details about the Company’s interest rate swap agreements and commodityderivative contracts, see Part II. Item 7. “Management’sDiscussion and Analysis of Financial Condition and Results of Operation” andItem 7A. “Quantitative and Qualitative Disclosures About Market Risk.”  See alsoNote 8 and Note 9.

 

**Recent Developments**

 

***Acquisitions***

 

On January 31, 2008, the Company completed the acquisition ofcertain oil and gas properties, effective October 1, 2007, locatedprimarily in the Mid-Continent region from Lamamco Drilling Company for acontract price of $552.2 million, subject to purchase price adjustments.  The acquired reserves are approximately 88%oil and over 70% proved developed with a low base decline rate of approximately5% and a reserve life index of over 34 years. This acquisition provides a large inventory of approximately 800development projects which the Company anticipates will create future organicgrowth opportunities.  The acquisitionwas financed with a combination of borrowings under the Company’s creditfacility and proceeds from a term loan entered into at closing.  See Note 2 for additional details.

 

On January 4,2008, the Company completed the acquisition of certain gas properties,effective November 1, 2007, located in the Appalachian Basin from K V Oiland Gas, Inc. for contract consideration of 600,000 units (approximately$14.7 million), subject to purchase price adjustments.

 

***Distributions***

 

In January 2008, the Company’s Board of Directors declared a cashdistribution of $0.63 per unit with respect to the fourth quarter of 2007.  The distribution totaled approximately $72.2 million and waspaid on February 14, 2008 to unitholders of record as of the close ofbusiness on February 8, 2008.  Thisdistribution represents a 10.5% increase in the Company’s annualized cash distributionrate, to $2.52 per unit, from $2.28 per unit for the third quarter of 2007.

 

3

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**Item 1.    Business and Properties - Continued**

 

***Private Placements***

 

During 2007 and 2006, the Company closed four private placements ofunits to groups of institutional investors.

 
| **Date Issued**         | ** ** | **Gross  Proceeds** | ** ** | **Units Issued** | ** ** | **Date Converted  to Units****(1)** | ** ** | **Date Registered  With SEC** | ** **         | **Date Lock-Up  Expired****(2)** | ** **             |
|-------------------------|------------|---------------------|------------|------------------|------------|-------------------------------------|------------|-------------------------------|--------------------|----------------------------------|------------------------|
| ** **              | ** ** | **(in thousands)**  | ** ** | ** **       | ** ** | ** **                          | ** ** | ** **                    | ** **         | ** **                       | ** **             |
| **August 2007:**   | ** ** | ** **          | ** ** | ** **       | ** ** | ** **                          | ** ** | ** **                    | ** **         | ** **                       | ** **             |
| Units                   |       | $                   | 416,000    |             | 12,999,989 |                                |       |                          | December 2007 |                             | February 14, 2008 |   |
| D Units                 |       | 1,084,000           |       | 34,997,005       |       | November 2007                  |       | December 2007            |               | February 14, 2008           |                   |
| ** **              |       | $                   | 1,500,000  |             | 47,996,994 |                                |       |                          |               |                             |                   |   |
| **June 2007:**     | ** ** | ** **          | ** ** | ** **       | ** ** | ** **                          | ** ** | ** **                    | ** **         | ** **                       | ** **             |
| Units                   |       | $                   | 260,000    |             | 7,761,194  |                                |       |                          | December 2007 |                             | February 14, 2008 |   |
| ** **              | ** ** | ** **          | ** ** | ** **       | ** ** | ** **                          | ** ** | ** **                    | ** **         | ** **                       | ** **             |
| **February 2007:** | ** ** | ** **          | ** ** | ** **       | ** ** | ** **                          | ** ** | ** **                    | ** **         | ** **                       | ** **             |
| Units                   |       | $                   | 172,904    |             | 6,650,144  |                                |       |                          | December 2007 |                             | December 14, 2007 |   |
| C Units                 |       | 187,096             |       | 7,465,946        |       | April 2007                     |       | December 2007            |               | December 14, 2007           |                   |
| ** **              |       | $                   | 360,000    |             | 14,116,090 |                                |       |                          |               |                             |                   |   |
| **October 2006:**  | ** ** | ** **          | ** ** | ** **       | ** ** | ** **                          | ** ** | ** **                    | ** **         | ** **                       | ** **             |
| Units                   |       | $                   | 116,228    |             | 5,534,687  |                                |       |                          | December 2007 |                             | December 14, 2007 |   |
| B Units                 |       | 188,772             |       | 9,185,965        |       | January 2007                   |       | December 2007            |               | December 14, 2007           |                   |
|                    |       | $                   | 305,000    |             | 14,720,652 |                                |       |                          |               |                             |                   |   |

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| (1)    |   | Not applicable  for units.                                                                                                   |
|--------|--------|------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                         |
| (2)    |   | Lock-up  expiration date represents date investors were allowed to sell or transfer  units per terms of purchase agreements. |

 

The proceeds from the private placements, net of expenses, were used tofinance acquisitions and to repay indebtedness under the Company’s creditfacility. See Note 4 for additional details about the private placements.

 

**Operating Regions**

 

***Mid-Continent***

 

**The Mid-Continent is the Company’s largest region, and as noted above,includes two key core operating areas. First, the Texas Panhandle area, which consists of shallow oil and gasproduction from the Brown Dolomite formation at depths of approximately 3,200feet and the Deep Granite Wash formation which produces at depths ranging from8,900 feet to 16,000 feet.  The second core area is located primarilyin Oklahoma.  Producing depths range from 6,000 feet to 20,000 feet inthis area.**

 

Texas Panhandleproved reserves represented approximately 33%, of total proved reserves at December 31,2007, of which 53% were proved developed reserves.  This area produced 71.6 MMcfe/d, or 36%, ofthe Company’s fourth quarter 2007 production. During 2007, the Company invested approximately $104.0 million to drillin the Texas Panhandle.  During 2008, theCompany anticipates spending 60% to 65% of its total capital budget fordevelopment activities in this area.

 

The Oklahomaproved reserves represented approximately 41%, of total proved reserves at December 31,2007, of which 83% were proved developed reserves.  This area produced 92.7 MMcfe/d, or 46%, ofthe Company’s fourth quarter 2007 production. During 2007, the Company invested approximately $40.0 million to drillin Oklahoma.  During 2008, the Companyanticipates spending 25% to 30% of its total capital budget for developmentactivities in this area.

 

In order to moreefficiently transport its gas to market, the Company owns and operates anetwork of gas gathering systems comprised of approximately 800 miles ofpipeline and associated compression and metering facilities which connect tonumerous sales outlets in the Texas Panhandle.

 

4

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**Item 1.    Business and Properties - Continued**

 

***Appalachian Basin***

 

The AppalachianBasin includes fields in West Virginia and Pennsylvania.  Appalachian Basin proved reserves representedapproximately 12%, of total proved reserves at December 31, 2007, of which75% were proved developed reserves.  Thisregion produced 24.3 MMcfe/d, or 12%, of the Company’s fourth quarter 2007production.  During 2007, the Companyinvested approximately $34.3 million to drill in the Appalachian Basin.  During 2008, the Company anticipates spending10% to 12% of its total capital budget for development activities in theAppalachian Basin region.

 

The proximity ofthe Company’s properties in this region to major United States consumingmarkets allows the Company to receive premium pricing on this production.  In order to more efficiently transport itsgas to market, the Company owns and operates a network of gas gathering systemscomprised of approximately 1,000 miles of pipeline and associated compressionand metering facilities which connect to numerous sales outlets on seveninterstate and six intrastate pipelines in the Appalachian Basin.  During 2007, the Company investedapproximately $17.2 million to expand its network of pipeline in this region.

 

The Company alsoperforms limited gas gathering activities for others on non-jurisdictionalgathering systems, primarily in Pennsylvania. The Company aggregates these volumes with production and sells all thegas through meters to the same purchasers. These revenues are collected and distributed to the third partyproducers in the normal course of business.

 

***Western***

 

Western consistsof the Brea Olinda Field of the Los Angeles Basin in California.  The Brea Olinda Field was discovered in 1880and produces from the shallow Pliocene formation to the deeper Mioceneformation.  Western proved reservesrepresented approximately 14%, of total proved reserves at December 31,2007, of which 86% were proved developed reserves.  This region produced 11.6 MMcfe/d, or 6%, ofthe Company’s fourth quarter 2007 production. During 2007, the Company invested approximately $2.4 million to drill inthis region.  During 2008, the Companyanticipates spending less than 5% of its total capital budget for developmentactivities in the Western region.

 

The Western region alsoincludes the operation of a gas processing facility which processes producedgas from Company and third party wells.  Processed gas is utilized togenerate electricity which is used in the field to power equipment, resultingin reduced operating costs.  Revenues arealso generated from the sale of excess power and associated NGL.

 

**Drillingand Acreage**

 

The following sets forth the wells drilled during the periods indicated(“gross” refers to the total wells in which the Company had a working interestand “net” refers to gross wells multiplied by its working interest):

 
| ** **                 | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------|------------|----------------------------------|------------|
| ** **                 | ** ** | **2007**                         | ** ** | **2006** | ** ** | **2005** | ** ** |
| **Gross wells:**           | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Productive                 |       | 247                              |       | 154 |   | 110 |   |
| Non-productive             |       | 6                                |       | 5 |   | — |   |
| Total                      |       | 253                              |       | 159 |   | 110 |   |
| **Net development wells:** | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Productive                 |       | 213                              |       | 147 |   | 105 |   |
| Non-productive             |       | 6                                |       | 5 |   | — |   |
| Total                      |       | 219                              |       | 152 |   | 105 |   |
| **Net exploratory wells:** | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Productive                 |       | —                           |       | — |   | — |   |
| Non-productive             |       | —                           |       | — |   | — |   |
| Total                      |       | —                           |       | — |   | — |   |

 

The totals abovedo not include 25 lateral segments added to existing vertical wellbores in theTexas Panhandle core operating area.  All of the non-productive wells in2007 were due to mechanical failures. The information should not be considered indicative of futureperformance, nor should it be assumed that there is necessarily any correlation

 

5

----

 

**Item 1.    Business and Properties - Continued**

 

between the numberof productive wells drilled, quantities of reserves found or economicvalue.  Productive wells are those thatproduce commercial quantities of oil, gas or NGL, regardless of whether theygenerate a reasonable rate of return.  AtDecember 31, 2007, the Company had 10 (9 net) wells in process.

 

The following sets forth information, as of December 31, 2007,relating to the Company’s drilling locations and net acres of leaseholdinterests in its three operating regions at that date:

 
| ** **                    | ** ** | **Mid-  Continent****(1)** | ** ** | **Appalachian  Basin** | ** ** | **Western** | ** ** | **Total****(2)** | ** ** |
|-------------------------------|------------|----------------------------|------------|------------------------|------------|-------------|------------|------------------|------------|
|                          |       |                       |       |                   |       |        |       |             |       |
| Proved undeveloped            |       | 852                        |       | 404                    |       | 2           |       | 1,258            |       |
| Other locations               |       | 2,359                      |       | 1,076                  |       | 6           |       | 3,441            |       |
| Total drilling  locations     |       | 3,211                      |       | 1,480                  |       | 8           |       | 4,699            |       |
|                          |       |                       |       |                   |       |        |       |             |       |
| Leasehold interests-net acres |       | 765,488                    |       | 182,186                |       | 3,961       |       | 951,635          |       |

----

| (1)    |   | Does not include  approximately 800 proved and other locations acquired in January 2008  with the Company’s acquisition of properties from Lamamco.  See “Recent Developments” above. |
|--------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                           |
| (2)    |   | Does not include  optimization projects.                                                                                                                                                                       |

 

As shown in thetable above, as of December 31, 2007, the Company had 1,258 provedundeveloped drilling locations (specific drilling locations as to which theindependent engineering firm, DeGolyer and MacNaughton, assigned provedundeveloped reserves as of such date) and the Company had identified 3,441additional unproved drilling locations (specific drilling locations as to whichDeGolyer and MacNaughton has not assigned any proved reserves) on acreage thatthe Company has under existing leases. As successful development wells frequently result in the reclassificationof adjacent lease acreage from unproved to proved, the Company expects that asignificant number of its unproved drilling locations will be reclassified asproved drilling locations prior to the actual drilling of these locations.

 

***Productive Wells***

 

The following table sets forth information relating tothe productive wells in which the Company owned a working interest as of December 31,2007.  Productive wells consist ofproducing wells and wells capable of production, including wells awaitingpipeline or other connections to commence deliveries.  “Gross” wells refers to the total number ofproducing wells in which the Company has an interest, and “net” wells refers tothe sum of its fractional working interests owned in gross wells.  The number of wells below do not includeapproximately 1,800 productive wells in which the Company owns a royaltyinterest only.

 
| ** **       | ** ** | **Gas Wells** | ** ** | **Oil Wells** | ** ** | **Total Wells** | ** ** |
|------------------|------------|---------------|------------|---------------|------------|-----------------|------------|
| ** **       | ** ** | **Gross**     | ** ** | **Net**       | ** ** | **Gross**       | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Operated (1)     |       | 4,133         |       | 3,421         |       | 1,505           |       | 1,406 |   | 5,638 |   | 4,827 |   |
| Non-operated (2) |       | 1,413         |       | 231           |       | 254             |       | 27 |   | 1,667 |   | 258 |   |
| Total (3)        |       | 5,546         |       | 3,652         |       | 1,759           |       | 1,433 |   | 7,305 |   | 5,085 |   |

----

| (1)    |   | 10 operated  wells had multiple completions at December 31, 2007.                                                            |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                              |
| (2)    |   | 3 non-operated  wells had multiple completions at December 31, 2007.                                                         |
|   |   |                                                                                                                              |
| (3)    |   | Does not include  approximately 2,450 gross wells acquired in January 2008.  See “Recent Developments” above. |

 

6

----

 

**Item 1.    Business and Properties - Continued**

 

***Developed and Undeveloped Acreage***

 

The following sets forth information as of December 31, 2007,relating to leasehold acreage:

 
| ** **   | ** ** | **Developed  Acreage** | ** ** | **Undeveloped  Acreage** | ** ** | **Total  Acreage** | ** ** |
|--------------|------------|------------------------|------------|--------------------------|------------|--------------------|------------|
| ** **   | ** ** | **Gross**              | ** ** | **Net**                  | ** ** | **Gross**          | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Operated     |       | 968,486                |       | 604,391                  |       | 356,793            |       | 215,288 |   | 1,325,279 |   | 819,679 |   |
| Non-operated |       | 641,397                |       | 100,506                  |       | 57,456             |       | 31,450 |   | 698,853 |   | 131,956 |   |
| Total        |       | 1,609,883              |       | 704,897                  |       | 414,249            |       | 246,738 |   | 2,024,132 |   | 951,635 |   |

 

**Production,Price and Cost History**

 

The Company’s gasproduction is primarily sold under market sensitive price contracts, whichtypically sell at differentials to the NYMEX or PEPL gas prices due to the Btucontent and the proximity to major consuming markets.  The Company’s gas production is sold topurchasers under percentage-of-proceeds contracts, percentage-of-indexcontracts or spot price contracts.  Bythe terms of the percentage-of-proceeds contracts, the Company receives apercentage of the resale price received by the purchaser for sales of residualgas and NGL recovered after transportation and processing of gas.  These purchasers sell the residual gas andNGL based primarily on spot market prices. Under percentage-of-index contracts, the price per MMBtu the Companyreceives for gas is tied to indexes published in *Gas Daily*or *Inside FERC Gas Market Report.*  Although exact percentages vary daily, as of December 31,2007, approximately 85% of the Company’s gas production was sold undershort-term contracts at market-sensitive or spot prices.  The remainder was sold under long-termcontracts.

 

The Company’s oil and NGLproduction is primarily sold under market sensitive percentage-of-indexcontracts and percentage-of-proceeds contracts and as of December 31,2007, approximately 60% of its oil production and 95% of its NGL production wassold under long-term contracts.

 

As discussed in the “Strategy” section above, the Company enters intoderivative transactions in the form of hedging arrangements to reduce theimpact of commodity price volatility on its cash flow from operations.  By removing price volatility from asignificant portion of its production, the Company has mitigated, but noteliminated, potential effects of fluctuating oil, gas and NGL prices on itscash flow from operations for those periods.

 

7

----

 

**Item 1.    Business and Properties - Continued**

 

The following sets forth information regarding net production of oil,gas and NGL and certain price information for each of the periods indicated:

 
| ** **                                     | ** ** | **Year Ended December 31,** | ** ** |
|------------------------------------------------|------------|----------------------------------|------------|
| ** **                                     | ** ** | **2007**                         | ** ** | **2006** | ** ** | **2005** | ** ** |
| **Production:**                                | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas production  (MMcf)                         |       | 27,001                           |       | 8,599 |   | 4,720 |   |
| Oil production  (MBbls)                        |       | 1,271                            |       | 370 |   | 20 |   |
| NGL production  (MBbls)                        |       | 992                              |       | — |   | — |   |
| Total production  (MMcfe)                      |       | 40,579                           |       | 10,818 |   | 4,839 |   |
| Average daily  production (MMcfe/d)            |       | 111.2                            |       | 29.6 |   | 13.3 |   |
| ** **                                     | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Weighted average prices (hedged):**(1)       | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas (Mcf)                                      |       | $                                | 8.19       |   | $ | 9.79 |   | $ | 6.45 |   |
| Oil (Bbl) (2)                                  |       | $                                | 66.15      |   | $ | 58.68 |   | $ | 52.55 |   |
| NGL (Bbl)                                      |       | $                                | 56.75      |   | $ | — |   | $ | — |   |
| Total (Mcfe)                                   |       | $                                | 8.91       |   | $ | 9.79 |   | $ | 6.51 |   |
|                                           |       |                             |       |   |   |   |   |
| **Weighted average prices (unhedged):**(3)     | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas (Mcf)                                      |       | $                                | 6.62       |   | $ | 7.17 |   | $ | 9.24 |   |
| Oil (Bbl) (2)                                  |       | $                                | 66.51      |   | $ | 50.68 |   | $ | 52.55 |   |
| NGL (Bbl)                                      |       | $                                | 55.51      |   | $ | — |   | $ | — |   |
| Total (Mcfe)                                   |       | $                                | 7.84       |   | $ | 7.43 |   | $ | 9.23 |   |
|                                           |       |                             |       |   |   |   |   |
| **Average unit costs per Mcfe of production:** | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Operating  expenses                            |       | $                                | 2.18       |   | $ | 1.67 |   | $ | 1.52 |   |
| General and  administrative expenses (4)       |       | $                                | 1.41       |   | $ | 3.70 |   | $ | 0.69 |   |
| Depreciation,  depletion and amortization      |       | $                                | 2.41       |   | $ | 2.23 |   | $ | 1.51 |   |

----

| (1)    |   | Includes the  effect of realized gains on derivatives of $43.2 million and $25.5 million  and realized losses of $13.1 million for the years ended December 31,  2007, 2006 and 2005, respectively.                                                                                                                                                                                                                                                                                                                                                                                                  |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| (2)    |   | Oil production  in California is sold pursuant to a long-term contract at 79% of NYMEX, and  with gravity increase due to NGL being mixed into the oil stream, prices  realized average approximately 82% of NYMEX.                                                                                                                                                                                                                                                                                                                                                                                       |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| (3)    |   | Does not include the effect of realized gains and losses on  derivatives.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| (4)    |   | The measure for the years ended December 31, 2007 and 2006  includes approximately $13.9 million and $21.6 million of unit-based  compensation and unit warrant expense, respectively.  The measure for the year ended December 31,  2006 includes $2.0 million of IPO bonuses paid to certain executive  officers.  General and administrative  expenses excluding these amounts were $1.07 per Mcfe and $1.51 per Mcfe for  the years ended December 31, 2007 and 2006, respectively.  This is a non-GAAP measure used by Company  management to analyze its performance. |

 

8

----

 

**Item 1.    Business and Properties - Continued**

 

**Reserve Data**

 

***Proved Reserves***

 

Proved oil and gasreserves are the estimated quantities of oil, gas and NGL which geological andengineering data demonstrate with reasonable certainty to be recoverable infuture years from known reservoirs under existing economic and operatingconditions, i.e., prices and costs as of the date the estimate is made.  Prices include consideration of changes inexisting prices provided by contractual arrangements, but not escalations basedon future conditions.  For additionalinformation regarding estimates of oil, gas and NGL reserves, includingestimates of proved and proved developed reserves, the standardized measure ofdiscounted future cash flows and the changes in discounted future cash flows,see Supplemental Oil and Gas Data (Unaudited) in Item 8. “FinancialStatements and Supplementary Data.”

 

The followingpresents estimated net proved oil, gas and NGL reserves and the present valueof estimated proved reserves at December 31, 2007, 2006 and 2005, based onreserve reports prepared by independent engineers DeGolyer and MacNaughton at December 31,2007 and 2006 and a reserve report prepared by independent engineersSchlumberger Data and Consulting Services at December 31, 2005.  The Standardized Measure values shown are notintended to represent the market value of estimated oil, gas and NGL reservesat such dates.

 
| ** **                                                 | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                 | ** ** | **2007**              | ** ** | **2006** | ** ** | **2005** | ** ** |
| **Reserve data:****(1)**                                   | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** |
| Estimated net  proved reserves:                            |       |                  |       |   |   |   |   |
| Gas (Bcf)                                                  |       | 1,028.9               |       | 274.0 |   | 191.9 |   |
| Oil (MMBbls)                                               |       | 54.8                  |       | 30.0 |   | 0.2 |   |
| NGL (MMBbls)                                               |       | 43.1                  |       | — |   | — |   |
| Total (Bcfe)                                               |       | 1,616.1               |       | 454.1 |   | 193.2 |   |
| Proved developed  (Bcfe)                                   |       | 1,172.1               |       | 314.1 |   | 125.2 |   |
| Proved  undeveloped (Bcfe)                                 |       | 444.0                 |       | 140.0 |   | 68.0 |   |
| Proved developed  reserves as a % of total proved reserves |       | 72.5                  | %          | 69.2 | % | 64.8 | % |
| **Standardized measure**(in millions)******(2)**           |       | $                     | 3,458.2    |   | $ | 552.3 |   | $ | 552.1 |   |
| **Representative oil and gas prices at period end:**       | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas — NYMEX per  MMBtu                                |       | $                     | 6.80       |   | $ | 5.64 |   | $ | 10.08 |   |
| Oil — NYMEX West  Texas Intermediate per Bbl          |       | $                     | 95.92      |   | $ | 61.05 |   | $ | 57.98 |   |

----

| (1)    |   | Excludes  reserves of approximately 329.4 Bcfe based on internal Company estimates for  the January 2008 acquisitions discussed in “Recent Developments” above.                                                                                                                                                                                                                             |
|--------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                       |
| (2)    |   | Does not give  effect to derivative contracts.  For  additional details about the Company’s derivative  contracts, see Part II. Item 7. “Management’s Discussion and  Analysis of Financial Condition and Results of Operation” and Item 7A.  “Quantitative and Qualitative Disclosures About Market Risk.”  See also  Note 8 and Note 9. |

 

The data in the above table are estimates.  Oil and gas reserve engineering is inherentlya subjective process of estimating underground accumulations of oil and gasthat cannot be measured exactly.  Theaccuracy of any reserve estimate is a function of the quality of available dataand engineering and geological interpretation and judgment.  Accordingly, reserve estimates may vary fromthe quantities of oil and gas that are ultimately recovered.

 

These reserve estimates are reviewed and approved by Company seniorengineering staff and management, with final approval by its Chief OperatingOfficer.  The process performed by theindependent engineers to prepare reserve amounts included their estimation ofreserve quantities, future producing rates, future net revenue and the presentvalue of such future net revenue.  Theindependent engineering firms also prepared estimates with respect to reservecategorization, using the definitions for proved reserves set forth inRegulation S-X Rule 4-10(a) and subsequent SEC staffinterpretations and guidance.  In theconduct of their preparation of the reserve estimates, the independentengineering firms did not independently verify the accuracy and completeness ofinformation and data furnished by the Company with respect to ownershipinterests, oil and gas production, well test data, historical costs of operationand development, product prices, or any agreements relating to current andfuture operations of the properties and sales of production.  However, if in the course of their work,something came to their attention which brought into question the validity orsufficiency of any such information or data, they did not rely on suchinformation or data until they had satisfactorily resolved their questionsrelating thereto.  Their estimates ofreserves conform to the guidelines of the SEC, including the criteria of “reasonablecertainty,” as it pertains to expectations 

 

9

----

 

**Item 1.    Business and Properties - Continued**

 

about the recoverability of reserves in future years, under existingeconomic and operating conditions.  TheCompany has not filed reserve estimates with any Federal authority or agency,with the exception of the SEC, since the last fiscal year ended.

 

Future prices received for production may vary, perhaps significantly,from the prices assumed for purposes of the estimate of StandardizedMeasure.  The Standardized Measure shownshould not be construed as the market value of the reserves at the datesshown.  The 10% discount factor requiredto be used pursuant to Statements of Financial Accounting Standards (“SFAS”) No. 69,*“Disclosures about Oil and Gas ProducingActivities,”* when calculating discounted future net cash flows, maynot be the most appropriate discount factor based on interest rates in effectfrom time to time and risks associated with the Company or the oil and gasindustry.  The Standardized Measure, nomatter what discount rate is used, is materially affected by assumptions as totiming of future production, which may prove to be inaccurate.

 

**Oil, Gas and NGL Sales - OperationalOverview**

 

***General***

 

The Company seeks to be the operator of its properties so that it cancontrol the drilling programs that not only replace production, but add valuethrough the growth of reserves and future operational synergies.  Many of the Company’s wells are completed inmultiple producing zones with commingled production and long economic lives.

 

***Principal Customers***

 

For the year endedDecember 31, 2007, sales of oil, gas and NGL to Duke Energy Corporation,Dominion Resources, Inc. and ConocoPhillips accounted for approximately21%, 20% and 12%, respectively, of the Company’s total volumes, or 53% in theaggregate.  If the Company were to loseany one of its major oil and gas purchasers, the loss could temporarily ceaseor delay production and sale of its oil and gas in that particular purchaser’sservice area.  If the Company were tolose a purchaser, it believes it could identify a substitute purchaser.  However, if one or more of these large gaspurchasers ceased purchasing oil and gas altogether, it could have adetrimental effect on the oil and gas market in general and on the volume ofoil and gas that it is able to sell.

 

***Competition***

 

The oil and gasindustry is highly competitive.  TheCompany encounters strong competition from other independent operators andmaster limited partnerships in acquiring properties, contracting for drillingand other related services and securing trained personnel.

 

The Company isalso affected by competition for drilling rigs and the availability of relatedequipment.  In the past, the oil and gasindustry has experienced shortages of drilling rigs, equipment, pipe andpersonnel, which has delayed development drilling and has caused significantprice increases.  The Company is unableto predict when, or if, such shortages may occur or how they would affect itsdrilling program.

 

***Operating Hazardsand Insurance***

 

The oil and gas industry involvesa variety of operating hazards and risks that could result in substantiallosses from, among other things, injury or loss of life, severe damage to ordestruction of property, natural resources and equipment, pollution or otherenvironmental damage, cleanup responsibilities, regulatory investigation andpenalties and suspension of operations.

 

In addition, the Company may beliable for environmental damages caused by previous owners of property itpurchases and leases.  As a result, theCompany may incur substantial liabilities to third parties or governmentalentities, the payment of which could reduce or eliminate funds available foracquisitions, development or distributions, or result in the loss ofproperties.

 

10

----

 

**Item 1.    Business and Properties - Continued**

 

In accordance with customaryindustry practices, the Company maintains insurance against some, but not all,potential losses.  The Company cannotprovide assurance that any insurance it obtains will be adequate to cover anylosses or liabilities.  The Companycannot predict the continued availability of insurance or the availability ofinsurance at premium levels that justify its purchase.  The Company has elected to self-insure fortrucks and vehicles licensed to operate on public highways and roads.  The Company may elect to self-insure foradditional items if it is determined that the cost of available insurance isexcessive relative to the risks presented. In addition, pollution and environmental risks generally are not fullyinsurable.  The occurrence of an eventnot fully covered by insurance could have a material adverse effect on theCompany’s financial position and results of operations.

 

The Company participates in asubstantial percentage of wells on a non-operated basis, and may be accordinglylimited in its ability to control the risks associated with oil, gas and NGL operations.

 

***Title to Properties***

 

Prior to thecommencement of drilling operations, the Company conducts a thorough titleexamination and performs curative work with respect to significantdefects.  To the extent title opinions orother investigations reflect title defects on those properties, the Company istypically responsible for curing any title defects at its expense prior tocommencing drilling operations.  Prior tocompleting an acquisition of producing gas leases, the Company performs titlereviews on the most significant leases and, depending on the materiality ofproperties, the Company may obtain a title opinion or review previouslyobtained title opinions.  As a result,the Company has obtained title opinions on a significant portion of its oil andgas properties and believes that it has satisfactory title to its producingproperties in accordance with standards generally accepted in the oil and gasindustry.  Oil and gas properties aresubject to customary royalty and other interests, liens for current taxes andother burdens which do not materially interfere with the use of or affect thecarrying value of the properties.

 

***Seasonal Nature ofBusiness***

 

Seasonal weatherconditions and lease stipulations can limit the drilling and producingactivities and other operations in certain regions of the United States thatthe Company operates in (primarily in parts of the Appalachian Basin and theMid-Continent).  These seasonal anomaliescan pose challenges for meeting the well drilling objectives and increasecompetition for equipment, supplies and personnel during the spring and summermonths, which could lead to shortages and increase costs or delay operations.

 

The demand for gastypically decreases during the summer months and increases during the wintermonths.  Seasonal anomalies such as mildwinters or hot summers sometimes lessen this fluctuation.  In addition, certain gas users utilize gasstorage facilities and purchase some of their anticipated winter requirementsduring the summer, which can also lessen seasonal demand fluctuations.  The demand for crude oil is generallydetermined at a global level, based on supply shortage concerns drivenprimarily by natural disasters such as hurricanes and by political instabilityin certain oil producing regions of the world.

 

**EnvironmentalMatters and Regulation**

 

The Company’s operations are subject to stringent federal, state andlocal laws and regulations governing the discharge of materials into theenvironment or otherwise relating to environmental protection.  The Company’s operations are subject to thesame environmental laws and regulations as other companies in the oil and gasindustry.  These laws and regulationsmay:

 
| · |   | require the  acquisition of various permits before drilling commences;                                                                                                                     |
|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| · |   | require the  installation of expensive pollution control equipment;                                                                                                                        |
| · |   | restrict the  types, quantities and concentration of various substances that can be  released into the environment in connection with drilling and production  activities;                 |
| · |   | limit or  prohibit drilling activities on lands lying within wilderness, wetlands and  other protected areas;                                                                              |
| · |   | require remedial  measures to prevent pollution from former operations, such as pit closure and  plugging of abandoned wells;                                                              |
| · |   | impose  substantial liabilities for pollution resulting from operations; and                                                                                                               |
| · |   | with respect to  operations affecting federal lands or leases, require preparation of a  Resource Management Plan, an Environmental Assessment, and/or an  Environmental Impact Statement. |

 

11

----

 

**Item 1.    Business and Properties - Continued**

 

These laws, rules andregulations may also restrict the rate of oil and gas production below the ratethat would otherwise be possible.  Theregulatory burden on the oil and gas industry increases the cost of doingbusiness and consequently affects profitability.  Additionally, Congress and federal and stateagencies frequently revise environmental laws and regulations, and any changesthat result in more stringent and costly waste handling, disposal and clean-uprequirements for the oil and gas industry could have a significant impact onoperating costs.

 

The environmentallaws and regulations applicable to the Company and its operations include,among others, the following United States federal laws and regulations:

 
| · |   | Clean Air Act, and its  amendments, which governs air emissions;                                                                                                                                              |
|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| · |   | Clean Water Act, which governs discharges to waters  of the United States;                                                                                                                                    |
| · |   | Comprehensive  Environmental Response, Compensation and Liability Act, which imposes  liability where hazardous releases have occurred or are threatened to occur  (commonly known as “Superfund”); |
| · |   | Energy Independence and  Security Act of 2007, which prescribes new fuel economy standards and other  energy saving measures;                                                                                 |
| · |   | National Environmental Policy Act, which governs oil and gas production activities on  federal lands;                                                                                                         |
| · |   | Resource Conservation and Recovery Act, which governs the management  of solid waste;                                                                                                                         |
| · |   | Safe Drinking  Water Act, which governs the underground injection and disposal of  wastewater; and                                                                                                            |
| · |   | U.S. Department of Interior regulations, which  impose liability for pollution cleanup and damages.                                                                                                           |

 

In addition, theKyoto Protocol to the United Nations Framework Convention on Climate Change (“KyotoProtocol”) requires Annex I countries, including Canada and the UnitedKingdom, to reduce their emissions of carbon dioxide and other greenhousegases.  As a result of the ratificationof the Kyoto Protocol and the adoption of legislation or other regulatoryinitiatives designed to implement its objectives by the national and regionalgovernments, reductions in greenhouse gases from crude oil and natural gasproducers may be required which could result in, among other things, increasedoperating and capital expenditures for those producers.  Until such legislation or other regulatoryinitiatives are finalized, the impact of the Kyoto Protocol and any suchlegislation adopted as a result of its ratification remains uncertain.

 

Various statesregulate the drilling for, and the production, gathering and sale of, oil andgas, including imposing production taxes and requirements for obtainingdrilling permits.  States also regulatethe method of developing new fields, the spacing and operation of wells and theprevention of waste of oil and gas resources. States may regulate rates of production and may establish maximum dailyproduction allowables from gas wells based on market demand or resourceconservation, or both.  States do notregulate wellhead prices or engage in other similar direct economic regulation,but there can be no assurance that they will not do so in the future.  The effect of these regulations may be tolimit the amounts of oil, gas and NGL that may be produced from the Company’swells and to limit the number of wells or locations it can drill.  The oil and gas industry is also subject tocompliance with various other federal, state and local regulations andlaws.  Some of those laws relate tooccupational safety, resource conservation and equal opportunity employment.

 

The Companybelieves that it substantially complies with all current applicableenvironmental laws and regulations and that continued compliance with existingrequirements will not have a material adverse impact on its financial conditionor results of operations.  However, theCompany cannot predict how future environmental laws and regulations may impactits properties or operations.  For theyear ended December 31, 2007, the Company did not incur any materialcapital expenditures for installation of remediation or pollution controlequipment at any of the Company’s facilities. The Company is not aware of any environmental issues or claims that willrequire material capital expenditures during 2008 or that will otherwise have amaterial impact on its financial position or results of operations.

 

12

----

 

**Item 1.    Business and Properties- Continued**

 

**ExecutiveOfficers of the Company**

 
| **Name**              | ** ** | **Age** | ** ** | **Position  with the Company**                                  |
|-----------------------|------------|---------|------------|-----------------------------------------------------------------|
| Michael C. Linn       |       | 56      |       | Chairman and  Chief Executive Officer                           |
| Mark E. Ellis         |       | 52      |       | President and  Chief Operating Officer                          |
| Kolja Rockov          |       | 37      |       | Executive Vice  President and Chief Financial Officer           |
| Lisa D. Anderson      |       | 47      |       | Senior Vice  President and Chief Accounting Officer             |
| Charlene A.  Ripley   |       | 44      |       | Senior Vice  President, General Counsel and Corporate Secretary |
| Arden L. Walker,  Jr. |       | 48      |       | Senior Vice  President - Operations and Chief Engineer          |

 

*Michael C.Linn*is theChairman and Chief Executive Officer of the Company and has served in suchcapacity since December 2007.  Priorto that, from June 2006 to December 2007, Mr. Linn served asChairman, President and Chief Executive Officer and from March 2003 to June 2006,he was the President, Chief Executive Officer and Director.  From 2000 to 2003 Mr. Linn was Presidentof Allegheny Interests, Inc., a private oil and gas investmentcompany.  From 1980 to 1999, Mr. Linnserved as General Counsel (1980-1982), Vice President (1982-1987), President(1987-1990) and CEO (1990-1999) of Meridian Exploration, a private AppalachianBasin oil and gas company that was sold to Columbia Natural Gas Company in1999.  Both Allegheny Interests andMeridian Exploration were wholly owned by Mr. Linn and his family.  Mr. Linn is the immediate past Chairmanof the Independent Petroleum Association of America, the largest national tradeassociation of independent oil and gas producers.  He currently sits on the Boards of theNational Petroleum Council and the American Exploration and Production Counciland is a member of the oil and gas industry’s 25 Year Club.  He was recently appointed as a Texasrepresentative to the Legal and Regulatory Affairs Committee of the InterstateOil and Gas Compact Commission.  He isalso Chairman of the Houston Wildcatters Committee of the Texas Alliance ofEnergy Producers.  Mr. Linn regularlyappears on behalf of the industry before state and federal agencies, such asthe Department of Energy, Department of the Treasury, Federal Energy RegulatoryCommission and the Environmental Protection Agency.  In addition, he has testified on behalf ofthe industry before various committees and subcommittees of the U.S. House ofRepresentatives and the U.S. Senate and is regularly quoted and has publishedvarious articles for trade publications and newspapers.  He is also a frequent guest on radio and televisionprograms representing the industry.  Hiscivic affiliations include memberships on the Boards of Small Steps and theYouth Development Center, in addition to memberships on the American ArtCommittee of the Museum of Fine Arts Houston and the Corporate Committee ofTexas Children’s Hospital.

 

*Mark E.Ellis*is the President and Chief Operating Officer and has served in suchcapacity since December 2007.  From December 2006to December 2007, Mr. Ellis was the Executive Vice President and Chief OperatingOfficer of the Company.  Mr. Ellishas over 28 years of experience in the oil and gas industry, most recentlyserving as President, Lower 48 for ConocoPhillips from April 2006 to November 2006.  Prior to joining ConocoPhillips, Mr. Ellisserved as Senior Vice President of North American Production for BurlingtonResources from September 2004 to April 2006.  He served as President of BurlingtonResources Canada Ltd. in Calgary from October 2000 to September 2004.  Mr. Ellis joined Burlington Resources in1985 and also held the positions of Vice President of the San Juan Division,Vice President and Chief Engineer and Manager of Acquisitions.  He began his career at The Superior OilCompany, where he served in several engineering positions in the Onshore andOffshore divisions.  Mr. Ellis is amember of the Society of Petroleum Engineers and a past board member of the NewMexico Oil & Gas Association, the Board of Governors of the CanadianAssociation of Petroleum Producers and served on the Foundation Board of theAlberta Children’s Hospital.  Mr. Elliscurrently serves on the Board of The Center for Hearing and Speech in Houston,Industry Board of Petroleum Engineering at Texas A&M University and theVisiting Committee of Petroleum Engineering at the Colorado School of Mines.

 

*KoljaRockov* is theExecutive Vice President and Chief Financial Officer.  Mr. Rockov has over 15 years of experience inthe oil and gas finance industry. From October 2004 until he joined LinnEnergy in March 2005, Mr. Rockov served as a Managing Director in theEnergy Group at RBC Capital Markets, where he was primarily responsible forinvestment banking coverage of the U.S. exploration and production sector.  From September 2000 until October 2004,Mr. Rockov was a Director at RBC Capital Markets.  Prior to September 2000, Mr. Rockovheld various senior positions with Dain Rauscher Wessels and Rauscher PierceRefsnes, Inc., predecessors of RBC Capital Markets.

 

13

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**Item 1.    Business and Properties- Continued**

 

*Lisa D. Anderson*has been the Senior Vice President andChief Accounting Officer since July 2006. Ms. Anderson oversees the Company’s accounting, financialreporting, information technology, treasury, tax and internal control functions.  Her career spans over 25 years of financialaccounting and consulting experience and includes previous leadership positionswith international risk consulting firms and as an audit partner with a majorinternational accounting firm, where she specialized in the oil and gasindustry.  Before joining the Company,she was the Managing Director leading the Financial Reporting Risk Servicespractice for Protiviti from November 2005 until July 2006.  She served as a Managing Director withJefferson Wells from January 2002 to August 2005.  Prior to 2002, she was an Assurance Partnerwith KPMG LLP.  Ms. Anderson is aCertified Public Accountant and a Certified Internal Auditor.  She is a member of the American Institute ofCertified Public Accountants, Texas Society of CPAs and the Institute ofInternal Auditors.  In addition, she hasserved on the Presidential Advisory and the Educational Curriculum Committeesof the Texas Society of Certified Public Accountants and currently serves onthe Board of the Greater Houston Convention and Visitors Bureau.

 

*CharleneA. Ripley*is theSenior Vice President, General Counsel and Corporate Secretary and has servedin that position since April 2007. Prior to joining the Company, Ms. Ripley held the position of VicePresident, General Counsel, Corporate Secretary and Chief Compliance Officer atAnadarko Petroleum Corporation from 2006 until April 2007 and served asVice President, General Counsel and Corporate Secretary from 2004 until 2006,Vice President and General Counsel from 2003 to 2004 and Vice President,General Counsel and Secretary of Anadarko Canada Corporation and itspredecessor companies since 1998.  Sheserved as Senior Counsel for Norcen Energy Resources Limited from 1997 to 1998.

 

*ArdenL. Walker, Jr.*isthe Senior Vice President - Operations and Chief Engineer of the Company.  Mr. Walker joined the Company in February 2007to oversee its Western operations, which includes California, Oklahoma andTexas.  In addition, Mr. Walkerserves in the capacity of chief engineer for the Company and is responsible forthe Company’s reserve review and booking processes.  From April 2006 until he joined theCompany in February 2007, Mr. Walker served as Asset DevelopmentManager, San Juan Business Unit for ConocoPhillips Company.  From June 2004 to April 2006, Mr. Walkerserved as General Manager, Asset Development in San Juan Division forBurlington Resources.  From January 2002until June 2004, Mr. Walker served as Business Development Manager inSan Juan Division for Burlington Resources. Mr. Walker began his career with El Paso Exploration Company in1982 and has served in a broad range of engineering, business development andmanagement positions with Burlington Resources since that time.  Mr. Walker is a member of the Society ofPetroleum Engineers, Independent Petroleum Association of America andCalifornia Independent Petroleum Association.

 

14

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**Item 1.    Business and Properties - Continued**

 

**Employees**

 

As of December 31,2007, the Company employed approximately 525 personnel.  None of the employees are represented bylabor unions or covered by any collective bargaining agreement.  The Company believes that its relationshipwith its employees is satisfactory.

 

**Principal Executive Offices**

 

The Company is aDelaware limited liability company with headquarters in Texas.  The principal executive offices are locatedat 600 Travis Street, Suite 5100, Houston, Texas 77002.  The main telephone number is (281) 840-4000.

 

**Company Website**

 

The Company’sinternet address is www.linnenergy.com. The Company makes available free of charge on or through its websiteAnnual Reports on Form 10-K, Quarterly Reports on Form 10-Q, CurrentReports on Form 8-K, and any amendments to those reports filed orfurnished pursuant to Section 13(a) or 15(d) of the SecuritiesExchange Act of 1934 as soon as reasonably practicable after the Companyelectronically files such material with, or furnishes it to, the SEC.  Information on the Company’s website shouldnot be considered a part of, or incorporated by reference into, this AnnualReport on Form 10-K.

 

The SEC maintainsan internet website that contains these reports at www.sec.gov.  Any materials that the Company files with theSEC may be read or copied at the SEC’s Public Reference Room at 100 FStreet, NE, Washington, DC 20549. Information concerning the operation of the Public Reference Room maybe obtained by calling the SEC at (800) 732-0330.

 

**Forward-Looking Statements**

 

This Annual Reporton Form 10-K contains forward-looking statements that are subject to anumber of risks and uncertainties, many of which are beyond the Company’scontrol.  These statements may includestatements about the Company’s:

 
| · |   | business  strategy;                                                                                |
|--------|--------|----------------------------------------------------------------------------------------------------|
| · |   | acquisition strategy;                                                                              |
| · |   | financial  strategy;                                                                               |
| · |   | drilling  locations;                                                                               |
| · |   | oil, gas and NGL  reserves;                                                                        |
| · |   | realized oil,  gas and NGL prices;                                                                 |
| · |   | production  volumes;                                                                               |
| · |   | lease operating  expenses, general and administrative expenses and finding and development  costs; |
| · |   | future operating  results; and                                                                     |
| · |   | plans,  objectives, expectations and intentions.                                                   |

 

All of these typesof statements, other than statements of historical fact included in this AnnualReport on Form 10-K, are forward-looking statements.  These forward-looking statements may be foundin Part I. Item 1. “Business and Properties;” Part I.Item 1A. “Risk Factors;” Part II. Item 7. “Management’sDiscussion and Analysis of Financial Condition and Results of Operation” andother items within this Annual Report on Form 10-K.  In some cases, forward-looking statements canbe identified by terminology such as “may,” “will,” “could,” “should,” “expect,”“plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,”“pursue,” “target,” “continue,” the negative of such terms or other comparableterminology.

 

Theforward-looking statements contained in this Annual Report on Form 10-Kare largely based on Company expectations, which reflect estimates andassumptions made by Company management. These estimates and assumptions reflect management’s best judgment basedon currently known market conditions and other factors.  Although the Company believes such estimatesand assumptions to be reasonable, they are inherently uncertain and involve anumber of risks and uncertainties beyond its control.  In addition, management’s assumptions mayprove to be inaccurate.  The Companycautions that the forward-looking statements contained in this Annual Report on

 

15

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**Item 1.    Business and Properties - Continued**

 

Form 10-K arenot guarantees of future performance, and it cannot assure any reader that suchstatements will be realized or the forward-looking statements or events willoccur.  Actual results may differmaterially from those anticipated or implied in forward-looking statements dueto factors listed in the “Risk Factors” section and elsewhere in this AnnualReport on Form 10-K.  Theforward-looking statements speak only as of the date made, and other than asrequired by law, the Company undertakes no obligation to publicly update orrevise any forward-looking statement, whether as a result of new information,future events or otherwise.

 

**Securities Act Disclaimer**

 

This Form 10-K doesnot constitute an offer to sell or the solicitation of an offer to buy anysecurities.

 

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** **

**Item 1A.Risk Factors**

 

Our business hasmany risks.  Factors that couldmaterially adversely affect our business, financial condition, operatingresults or liquidity and the trading price of our units are described below.  This information should be consideredcarefully, together with other information in this report and other reports andmaterials we file with the SEC.

 

**Risks Related to Our Business**

 

***We may not have sufficient cashflow from operations to pay the quarterly distribution at the current distributionlevel and future distributions to our unitholders may fluctuate from quarter toquarter.***

 

We may not havesufficient cash flow from operations each quarter to pay the quarterlydistribution at the current distribution level. Under the terms of our limited liability company agreement, the amountof cash otherwise available for distribution will be reduced by our operatingexpenses and any cash reserve amounts that our Board of Directors establishesto provide for future operations, future capital expenditures, future debtservice requirements and future cash distributions to our unitholders.  The amount of cash we can distribute on ourunits principally depends upon the amount of cash we generate from our operations,which will fluctuate from quarter to quarter based on, among other things:

 

·**                 **produced volumes of oil, gas and NGL;

·**                 **prices at which oil, gas and NGLproduction is sold;

·**                 **level of our operating costs;

·**                 **payment of interest, which depends on theamount of our indebtedness and the interest payable thereon; and

·**                 **level of our capital expenditures.

 

In addition, the actual amount of cash we will have available fordistribution will depend on other factors, some of which are beyond ourcontrol, including:

 

·**                 **availability of borrowings under ourcredit facility to pay distributions;

·**                 **the costs of acquisitions, if any;

·**                 **fluctuations in our working capitalneeds;

·**                 **timing and collectibility of receivables;

·**                 **restrictions on distributions containedin our credit facility;

·**                 **prevailing economic conditions; and

·**                 **the amount of cash reserves establishedby our Board of Directors for the proper conduct of our business.

 

As a result ofthese factors, the amount of cash we distribute to our unitholders in anyquarter may fluctuate significantly from quarter to quarter and may besignificantly less than the current distribution level.

 

***We actively seek to acquire oiland gas properties.  Acquisitions involvepotential risks that could adversely impact our future growth and our abilityto increase or pay distributions.***

 

Any acquisitioninvolves potential risks, including, among other things:

 

·**                 **the risk that reserves expected tosupport the acquired assets may not be of the anticipated magnitude or may notbe developed as anticipated;

·**                 **inaccurate assumptions about revenues andcosts, including synergies;

·**                 **significant increases in our indebtednessand working capital requirements;

·**                 **an inability to transition and integratesuccessfully or timely the businesses we acquire;

·**                 **the cost of transition and integration ofdata systems and processes;

·**                 **the potential environmental problems andcosts;

·**                 **the assumption of unknown liabilities;

·**                 **limitations on rights to indemnity fromthe seller;

·**                 **the diversion of management’s attentionfrom other business concerns;

 

 

17

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**Item 1A****.****Risk Factors - Continued**

 

·**                 **increased demands on existing personneland on our corporate structure;

·**                 **customer or key employee losses of theacquired businesses; and

·**                 **the failure to realize expected growth orprofitability.

 

The scope and costof these risks may ultimately be materially greater than estimated at the timeof the acquisition.  Further, our futureacquisition costs may be higher than those we have achieved historically.  Any of these factors could adversely impactour future growth and our ability to increase or pay distributions.

 

***If we do not make futureacquisitions on economically acceptable terms, then our growth and ability toincrease distributions will be limited.***

 

Our ability togrow and to increase distributions to our unitholders is partially dependent onour ability to make acquisitions that result in an increase in available cashflow per unit.  We may be unable to makesuch acquisitions because we are:

 

·**                 **unable to identify attractive acquisitioncandidates or negotiate acceptable purchase contracts with them;

·**                 **unable to obtain financing for theseacquisitions on economically acceptable terms; or

·**                 **outbid by competitors.

 

In any such case,our future growth and ability to increase distributions will be limited.  Furthermore, even if we do make acquisitionsthat we believe will increase available cash flow per unit, these acquisitionsmay nevertheless result in a decrease in available cash flow per unit.

 

***We have significant indebtednessunder our credit facility and term loan. These facilities have substantial restrictions and financial covenantsand we may have difficulty obtaining additional credit, which could adverselyaffect our operations and our ability to pay distributions to our unitholders.***

 

We havesignificant indebtedness under our credit facility and term loan.  As of January 31, 2008, we had anaggregate of approximately $1.99 billion outstanding under our credit facilityand term loan (with additional borrowing capacity of approximately $314.5 million).  As a result of our indebtedness, we will usea portion of our cash flow to pay interest and principal when due, which willreduce the cash available to finance our operations and other businessactivities and could limit our flexibility in planning for or reacting tochanges in our business and the industry in which we operate.  The amount of our indebtedness may also causeus to be more vulnerable to economic downturns and adverse developments in ourbusiness.  Our ability to access thecapital markets to raise capital on favorable terms will be affected by ourdebt level and by adverse market conditions resulting from, among other things,general economic conditions, contingencies and uncertainties that are difficultto predict and impossible to control. Such a development could adversely affect our ability to obtainfinancing for working capital, capital expenditures or acquisitions or torefinance existing indebtedness.

 

We depend on thesefacilities for future capital needs and to fund our distributions.  The credit facility and term loan restrictour ability to obtain additional financing, make investments, lease equipment,sell assets and engage in business combinations.  We also are required to comply with certainfinancial covenants and ratios.  Ourability to comply with these restrictions and covenants in the future isuncertain and will be affected by the levels of cash flow from our operationsand events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants couldresult in a default, which could cause all of our existing indebtedness to beimmediately due and payable.

 

As noted above, wedepend on our credit facility for future capital needs.  In addition, we have drawn on our creditfacility to fund or partially fund quarterly cash distribution payments, sincewe use operating cash flows for investing activities and borrow as cash isneeded.  Absent such borrowing, we wouldhave at times experienced a shortfall in cash available to pay our declaredquarterly cash distribution amount.  Ifthere is a default under our credit facility, we would be unable to makeborrowings to fund distributions.

 

Availability underour credit facility is determined semi-annually at the discretion of thelenders and is based in part on oil, gas and NGL prices.  The lenders can unilaterally adjust theborrowing base and the borrowings permitted to be outstanding under the creditfacility.  Any increase in the borrowingbase requires the consent of all the lenders. 

 

18

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**Item 1A****.****Risk Factors - Continued**

 

Outstandingborrowings in excess of the borrowing base must be repaid immediately, or wemust pledge other properties as additional collateral.  We do not currently have any substantialunpledged properties, and we may not have the financial resources in the futureto make any mandatory principal prepayments required under the creditfacility.  Significant declines in ourproduction or significant declines in realized oil, gas or NGL prices forprolonged periods and resulting decreases in our borrowing base may force us toreduce or suspend distributions to our unitholders.

 

***Increases in interest rates couldadversely affect the demand for our units.***

 

An increase in interestrates may cause a corresponding decline in demand for equity investments, inparticular for yield-based equity investments such as our units.  Any such reduction in demand for our unitsresulting from other more attractive investment opportunities may cause thetrading price of our units to decline.

 

***Our hedging activities couldresult in financial losses or could reduce our income, which may adverselyaffect our ability to pay distributions to our unitholders.***

 

To achieve morepredictable cash flow and to reduce our exposure to adverse fluctuations in theprices of oil, gas and NGL, we enter into hedging arrangements for asignificant portion of our production. If we experience a sustained material interruption in our production orif we are unable to perform our drilling activity as planned, we might beforced to satisfy all or a portion of our hedging obligations without thebenefit of the cash flow from our sale of the underlying physical commodity,resulting in a substantial reduction of our liquidity.

 

***If commodityprices decline significantly for a prolonged period, our cash flow fromoperations will decline, and we may have to lower our distribution or may notbe able to pay distributions at all.***

 

Our revenue,profitability and cash flow depend upon the prices of and demand for oil, gasand NGL.  The oil, gas and NGL market isvery volatile and a drop in prices can significantly affect our financialresults and impede our growth.  Changesin oil, gas and NGL prices have a significant impact on the value of ourreserves and on our cash flow.  Pricesfor these commodities may fluctuate widely in response to relatively minorchanges in the supply of and demand for them, market uncertainty and a varietyof additional factors that are beyond our control, such as:

 

·**                 **the domestic and foreign supply of anddemand for oil, gas and NGL;

·      the price and level of foreign imports;

·**                 **the level of consumer product demand;

·**                 **weather conditions;

·**                 **overall domestic and global economicconditions;

·**                 **political and economic conditions in oiland gas producing countries, including those in the Middle East and SouthAmerica;

·**                 **the ability of members of theOrganization of Petroleum Exporting Countries to agree to and maintain priceand production controls;

·**                 **the impact of the U.S. dollar exchangerates on oil, gas and NGL prices;

·**                 **technological advances affecting energyconsumption;

·**                 **domestic and foreign governmentalregulations and taxation;

·**                 **the impact of energy conservationefforts;

·**                 **the proximity and capacity of pipelinesand other transportation facilities; and

·**                 **the price and availability of alternativefuels.

 

In the past, theprices of oil, gas and NGL have been extremely volatile, and we expect thisvolatility to continue.  If commodityprices decline significantly for a prolonged period, our cash flow fromoperations will decline, and we may have to lower our distribution or may notbe able to pay distributions at all.

 

 

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**Item 1A****.****Risk Factors - Continued**

 

***Future price declines or downwardreserve revisions may result in a write-down of our asset carrying values.***

 

Declines in oil, gas and NGL prices may result in our having to makesubstantial downward adjustments to our estimated proved reserves.  If this occurs, or if our estimates ofdevelopment costs increase, production data factors change or drilling resultsdeteriorate, accounting rules may require us to write-down, as a non-cashcharge to earnings, the carrying value of our properties for impairments.  We are required to perform impairment testson our assets periodically and whenever events or changes in circumstanceswarrant a review of our assets.  To theextent such tests indicate a reduction of the estimated useful life or estimatedfuture cash flows of our assets, the carrying value may not be recoverable andtherefore would require a write-down.  Wemay incur impairment charges in the future, which could have a material adverseeffect on our results of operations in the period incurred and on our abilityto borrow funds under our credit facility, which in turn may adversely affectour ability to make cash distributions to our unitholders.

 

***Unless we replace our reserves,our reserves and production will decline, which would adversely affect our cashflow from operations and our ability to make distributions to our unitholders.***

 

Producing oil, gasand NGL reservoirs are characterized by declining production rates that varydepending upon reservoir characteristics and other factors.  The overall rate of decline for ourproduction will change if production from our existing wells declines in adifferent manner than we have estimated and can change when we drill additionalwells, make acquisitions and under other circumstances.  Thus, our future oil, gas and NGL reservesand production and, therefore, our cash flow and income, are highly dependenton our success in efficiently developing and exploiting our current reservesand economically finding or acquiring additional recoverable reserves.  We may not be able to develop, find oracquire additional reserves to replace our current and future production atacceptable costs, which would adversely affect our cash flow from operationsand our ability to make distributions to our unitholders.

 

***Our estimated reserves are basedon many assumptions that may prove to be inaccurate.  Any material inaccuracies in these reserveestimates or underlying assumptions will materially affect the quantities andpresent value of our reserves.***

 

No one can measureunderground accumulations of oil, gas and NGL in an exact way.  Reserve engineering requires subjectiveestimates of underground accumulations of oil, gas and NGL and assumptionsconcerning future oil, gas and NGL prices, production levels, and operating anddevelopment costs.  As a result,estimated quantities of proved reserves and projections of future productionrates and the timing of development expenditures may prove to beinaccurate.  Independent petroleumengineering firms prepare estimates of our proved reserves.  Some of our reserve estimates are madewithout the benefit of a lengthy production history, which are less reliablethan estimates based on a lengthy production history.  Also, we make certain assumptions regardingfuture oil, gas and NGL prices, production levels, and operating anddevelopment costs that may prove incorrect. Any significant variance from these assumptions by actual figures couldgreatly affect our estimates of reserves, the economically recoverablequantities of oil, gas and NGL attributable to any particular group ofproperties, the classifications of reserves based on risk of recovery andestimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserveestimates are based, as described above, often result in the actual quantitiesof oil, gas and NGL we ultimately recover being different from our reserveestimates.

 

The present valueof future net cash flows from our proved reserves is not necessarily the sameas the current market value of our estimated oil, gas and NGL reserves.  We base the estimated discounted future netcash flows from our proved reserves on prices and costs in effect on the day ofestimate.  However, actual future netcash flows from our oil and gas properties also will be affected by factorssuch as:

 

·**                 **actual prices we receive for oil, gas andNGL;

·**                 **the amount and timing of actualproduction;

·**                 **the timing and success of developmentactivities;

·**                 **supply of and demand for oil, gas andNGL; and

·**                 **changes in governmental regulations or taxation.

 

 

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**Item 1A****.****Risk Factors - Continued**

 

In addition, the10% discount factor, required to be used pursuant to Statement of AccountingStandard No. 69 when calculating discounted future net cash flows, may notbe the most appropriate discount factor based on interest rates in effect fromtime to time and risks associated with us or the oil and gas industry ingeneral.

 

***Our development operationsrequire substantial capital expenditures, which will reduce our cash availablefor distribution.  We may be unable toobtain needed capital or financing on satisfactory terms, which could lead to adecline in our reserves.***

 

The oil and gasindustry is capital intensive.  We makeand expect to continue to make substantial capital expenditures in our businessfor the development, production and acquisition of oil, gas and NGLreserves.  These expenditures will reduceour cash available for distribution.  Weintend to finance our future capital expenditures with cash flow fromoperations and our financing arrangements. Our cash flow from operations and access to capital are subject to anumber of variables, including:

 

·**                 **our proved reserves;

·**                 **the level of oil, gas and NGL we are ableto produce from existing wells;

·**                 **the prices at which we are able to sellour oil, gas and NGL; and

·**                 **our ability to acquire, locate andproduce new reserves.

 

If our revenues orthe borrowing base under our credit facility decrease as a result of lower oil,gas and NGL prices, operating difficulties, declines in reserves or for anyother reason, we may have limited ability to obtain the capital necessary tosustain our operations at current levels. Our credit facility restricts our ability to obtain new financing.  If additional capital is needed, we may notbe able to obtain debt or equity financing on terms favorable to us, or atall.  If cash generated by operations oravailable under our credit facility is not sufficient to meet our capital requirements,the failure to obtain additional financing could result in a curtailment of ourdevelopment operations, which in turn could lead to a possible decline in ourreserves.

 

***We may decide not to drill someof the prospects we have identified, and locations that we decide to drill maynot yield oil, gas and NGL in commercially viable quantities.***

 

Our prospectivedrilling locations are in various stages of evaluation, ranging from a prospectthat is ready to drill to a prospect that will require additional geologicaland engineering analysis.  Based on avariety of factors, including future oil, gas and NGL prices, the generation ofadditional seismic or geological information, the availability of drilling rigsand other factors, we may decide not to drill one or more of theseprospects.  As a result, we may not beable to increase or maintain our reserves or production, which in turn couldhave an adverse effect on our business, financial condition or results ofoperations.

 

The cost ofdrilling, completing and operating a well is often uncertain, and cost factorscan adversely affect the economics of a well. Our efforts will be uneconomic if we drill dry holes or wells that areproductive but do not produce enough oil, gas and NGL to be commercially viableafter drilling, operating and other costs. If we drill future wells that we identify as dry holes, our drillingsuccess rate would decline, which could have an adverse effect on our business,financial condition or results of operations.

 

***Our businessdepends on gathering and transportation facilities.  Any limitation in the availability of thosefacilities would interfere with our ability to market the oil, gas and NGL weproduce, and could reduce our cash available for distribution and adversely impactexpected increases in oil, gas and NGL production from our drilling program.***

 

The marketabilityof our oil, gas and NGL production depends in part on the availability,proximity and capacity of gathering and pipeline systems.  The amount of oil, gas and NGL that can beproduced and sold is subject to limitation in certain circumstances, such aspipeline interruptions due to scheduled and unscheduled maintenance, excessivepressure, physical damage to the gathering or transportation system, or lack ofcontracted capacity on such systems.  Thecurtailments arising from these and similar circumstances may last from a fewdays to several months.  In many cases,we are provided only with limited, if any, notice as to when thesecircumstances will arise and their duration. In addition, some of our wells are drilled in locations that are notserviced by gathering and transportation pipelines, or the gathering andtransportation pipelines in the area may not have sufficient capacity totransport 

 

 

21

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**Item 1A****.****Risk Factors - Continued**

 

additionalproduction.  As a result, we may not beable to sell the oil, gas and NGL production from these wells until thenecessary gathering and transportation systems are constructed.  Any significant curtailment in gatheringsystem or pipeline capacity, or significant delay in the construction ofnecessary gathering and transportation facilities, would interfere with ourability to market the oil, gas and NGL we produce, and could reduce our cashavailable for distribution and adversely impact expected increases in oil andgas production from our drilling program.

 

***We depend on certain keycustomers for sales of our oil, gas and NGL. To the extent these and other customers reduce the volumes they purchasefrom us or delay payment, our revenues and cash available for distributioncould decline.  Further, a generalincrease in non-payment could have an adverse impact on our financial conditionand results of operations.***

 

For the year endedDecember 31, 2007, Duke Energy Corporation, Dominion Resources, Inc.and ConocoPhillips accounted for approximately 21%, 20% and 12%, respectively,of our total volumes, or 53% in the aggregate. For the year ended December 31, 2006, Dominion Resources, Inc.and ConocoPhillips accounted for approximately 53%, and 14%, respectively, ofour total volumes, or 67% in the aggregate. To the extent these and other customers reduce the volumes of oil, gasor NGL that they purchase from us, our revenues and cash available fordistribution could decline.

 

***Many of our leases are in areasthat have been partially depleted or drained by offset wells.***

 

Our key project areas are located in some of the most active drillingareas of the producing basins in the United States.  As a result, many of our leases are in areasthat have already been partially depleted or drained by earlier offsetdrilling.  This may inhibit our abilityto find economically recoverable quantities of reserves in these areas.

 

Our identifieddrilling location inventories are scheduled out over several years, making themsusceptible to uncertainties that could materially alter the occurrence ortiming of their drilling, resulting in temporarily lower cash from operations,which may impact our ability to pay distributions.

 

Our management hasspecifically identified and scheduled drilling locations as an estimation ofour future multi-year drilling activities on our existing acreage.  As of December 31, 2007, we hadidentified 4,699 drilling locations, of which 1,258 were proved undevelopedlocations and 3,441 were other locations. These identified drilling locations represent a significant part of ourgrowth strategy.  Our ability to drilland develop these locations depends on a number of factors, including theavailability of capital, seasonal conditions, regulatory approvals, oil, gasand NGL prices, costs and drilling results. In addition, DeGolyer and MacNaughton has not estimated proved reservesfor the 3,441 other drilling locations we have identified and scheduled fordrilling, and therefore there may be greater uncertainty with respect to thesuccess of drilling wells at these drilling locations.  Our final determination on whether to drillany of these drilling locations will be dependent upon the factors describedabove as well as, to some degree, the results of our drilling activities withrespect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drillinglocations we have identified will be drilled within our expected timeframe orwill ever be drilled or if we will be able to produce oil, gas and NGL fromthese or any other potential drilling locations.  As such, our actual drilling activities maymaterially differ from those presently identified, which could adversely affectour business.

 

***Drilling for andproducing oil, gas and NGL are high risk activities with many uncertaintiesthat could adversely affect our financial condition or results of operationsand, as a result, our ability to pay distributions to our unitholders.***

 

Our drillingactivities are subject to many risks, including the risk that we will notdiscover commercially productive reservoirs. Drilling for oil, gas and NGL can be uneconomic, not only from dryholes, but also from productive wells that do not produce sufficient revenuesto be commercially viable.  In addition,our drilling and producing operations may be curtailed, delayed or canceled asa result of other factors, including:

 

·**                 **the high cost, shortages or deliverydelays of equipment and services;

·**                 **unexpected operational events;

·**                 **adverse weather conditions, particularlyseasonal weather conditions in the spring;

·**                 **facility or equipment malfunctions;

 

 

22

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**Item 1A****.****Risk Factors - Continued**

 

·**                 **title problems;

·**                 **pipeline ruptures or spills;

·**                 **compliance with environmental and othergovernmental requirements;

·**                 **unusual or unexpected geologicalformations;

·**                 **loss of drilling fluid circulation;

·**                 **formations with abnormal pressures;

·**                 **fires;

·**                 **blowouts, craterings and explosions; and

·**                 **uncontrollable flows of oil, gas and NGLor well fluids.

 

Any of theseevents can cause increased costs or restrict our ability to drill the wells andconduct the operations which we currently have planned.  Any delay in the drilling program orsignificant increase in costs could impact our ability to generate sufficientcash flow to pay quarterly distributions to our unitholders at the currentdistribution level.  Increased costscould include losses from personal injury or loss of life, damage to ordestruction of property, natural resources and equipment, pollution,environmental contamination, loss of wells and regulatory penalties. Weordinarily maintain insurance against certain losses and liabilities arisingfrom our operations.  However, it isimpossible to insure against all operational risks in the course of ourbusiness.  Additionally, we may elect notto obtain insurance if we believe that the cost of available insurance isexcessive relative to the perceived risks presented.  Losses could therefore occur for uninsurableor uninsured risks or in amounts in excess of existing insurance coverage.  The occurrence of an event that is not fullycovered by insurance could have a material adverse impact on our businessactivities, financial condition and results of operations.

 

***Because we handle oil, gas andNGL and other hydrocarbons, we may incur significant costs and liabilities inthe future resulting from a failure to comply with new or existingenvironmental regulations or an accidental release of hazardous substances intothe environment.***

 

The operations of our wells, gathering systems,turbines, pipelines and other facilities are subject to stringent and complexfederal, state and local environmental laws and regulations.  These include, for example:

 

·**                 **the federal Clean Air Act and comparablestate laws and regulations that impose obligations related to air emissions;

·**                 **the federal Clean Water Act andcomparable state laws and regulations that impose obligations related to dischargesof pollutants into regulated bodies of water;

·**                 **the federal Resource Conservation andRecovery Act (“RCRA”), and comparable state laws that impose requirements forthe handling and disposal of waste from our facilities; and

·**                 **the Comprehensive Environmental Response,Compensation and Liability Act of 1980 (“CERCLA”), also known as “Superfund,”and comparable state laws that regulate the cleanup of hazardous substancesthat may have been released at properties currently or previously owned or operatedby us or at locations to which we have sent waste for disposal.

 

Failure to comply with these laws and regulations may trigger a varietyof administrative, civil and criminal enforcement measures, including theassessment of monetary penalties, the imposition of remedial requirements, andthe issuance of orders enjoining future operations.  Certain environmental statutes, including theRCRA, CERCLA and analogous state laws and regulations, impose strict, joint andseveral liability for costs required to clean up and restore sites wherehazardous substances have been disposed of or otherwise released.  Moreover, it is not uncommon for neighboringlandowners and other third parties to file claims for personal injury andproperty damage allegedly caused by the release of hazardous substances orother waste products into the environment.

 

There is aninherent risk that we may incur environmental costs and liabilities due to thenature of our business and the substances we handle.  For example, an accidental release from oneof our wells or gathering pipelines could subject us to substantial liabilitiesarising from environmental cleanup and restoration costs, claims made byneighboring landowners and other third parties for personal injury and propertydamage, and fines or penalties for related violations of environmental laws orregulations.  Moreover, the possibilityexists that stricter laws, regulations or enforcement policies couldsignificantly increase our compliance costs and the cost of any remediationthat may become necessary.  We may not beable to recover these costs from insurance. For a more 

 

 

23

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**Item 1A****.****Risk Factors - Continued**

 

detaileddiscussion of environmental and regulatory matters impacting our business, see Part I.Item 1. “Business and Properties - Environmental Matters and Regulation.”

 

***We are subject to complexfederal, state, local and other laws and regulations that could adverselyaffect the cost, manner or feasibility of doing business.***

 

Our operations areregulated extensively at the federal, state and local levels.  Environmental and other governmental laws andregulations have increased the costs to plan, design, drill, install, operateand abandon oil and gas wells.  Underthese laws and regulations, we could also be liable for personal injuries,property damage and other damages. Failure to comply with these laws and regulations may result in thesuspension or termination of our operations and subject us to administrative,civil and criminal penalties.  Moreover,public interest in environmental protection has increased in recent years, andenvironmental organizations have opposed, with some success, certain drillingprojects.

 

Part of theregulatory environment in which we operate includes, in some cases, legalrequirements for obtaining environmental assessments, environmental impactstudies and/or plans of development before commencing drilling and productionactivities.  In addition, our activitiesare subject to the regulations regarding conservation practices and protectionof correlative rights.  These regulationsaffect our operations and limit the quantity of oil, gas and NGL we may produceand sell.  A major risk inherent in ourdrilling plans is the need to obtain drilling permits from state and localauthorities.  Delays in obtainingregulatory approvals or drilling permits, the failure to obtain a drillingpermit for a well or the receipt of a permit with unreasonable conditions orcosts could have a material adverse effect on our ability to develop ourproperties.  Additionally, the regulatoryenvironment could change in ways that might substantially increase thefinancial and managerial costs of compliance with these laws and regulationsand, consequently, adversely affect our ability to pay distributions to ourunitholders.  For a description of thelaws and regulations that affect us, see Part I. Item 1. “Business andProperties - Environmental Matters and Regulation.”

 

***As of December 31, 2007, weconcluded that our disclosure controls and procedures were effective.  If we fail to maintain an effective system ofinternal controls, we may not be able to accurately report our financialresults or prevent fraud.  As a result,current and potential unitholders could lose confidence in our financialreporting, which would harm our business and the trading price of our units.***

 

A company’sinternal control over financial reporting is a process designed to providereasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance withgenerally accepted accounting principles. Because of its inherent limitations, internal control over financialreporting may not prevent or detect misstatements.  Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls maybecome inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.  If we cannot provide reliable financialreports or prevent fraud, our reputation and operating results could beharmed.  We cannot be certain that ourefforts to maintain our internal controls will be successful, that we will beable to maintain adequate controls over our financial processes and reportingin the future or that we will be able to comply with our obligations under Section 404of the Sarbanes-Oxley Act of 2002.  Foradditional information, see Part II. Item 9A. “Controls andProcedures” in this Annual Report on Form 10-K for the year ended December 31,2007.

 

Any failure todevelop or maintain effective internal controls, or difficulties encountered inimplementing or improving our internal controls, could harm our operatingresults or cause us to fail to meet certain reporting obligations.  Ineffective internal controls could alsocause investors to lose confidence in our reported financial information, whichcould have a negative effect on the trading price of our units.

 

 

24

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**Item 1A****.****Risk Factors - Continued**

 

**Risks Related to Our Structure**

 

***Our management may have conflictsof interest with the untiholders.  Ourlimited liability company agreement limits the remedies available to ourunitholders in the event unitholders have a claim relating to conflicts ofinterest.***

 

Conflicts of interest may arise between our management on one hand, andthe Company and our unitholders on the other hand, related to the divergentinterests of our management.  Situationsin which the interests of our management may differ from interests of ournon-affiliated unitholders include, among others, the following situations:

 

·**                 **our limited liability company agreementgives our Board of Directors broad discretion in establishing cash reserves forthe proper conduct of our business, which will affect the amount of cashavailable for distribution.  For example,our management will use its reasonable discretion to establish and maintaincash reserves sufficient to fund our drilling program;

·**                 **our management team determines the timingand extent of our drilling program and related capital expenditures, assetpurchases and sales, borrowings, issuances of additional membership interestsand reserve adjustments, all of which will affect the amount of cash that wedistribute to our unitholders; and

·**                 **Affiliates of our directors are notprohibited from investing or engaging in other businesses or activities thatcompete with the Company.

 

***We do not have the sameflexibility as other types of organizations to accumulate cash and equity toprotect against illiquidity in the future.***

 

Unlike acorporation, our limited liability company agreement requires us to makequarterly distributions to our unitholders of all available cash reduced by anyamounts of reserves for commitments and contingencies, including capital andoperating costs and debt service requirements. The value of our units may decrease in direct correlation with decreasesin the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we mayhave difficulty issuing more equity to recapitalize.

 

***Our tax treatment depends on ourstatus as a partnership for federal income tax purposes, as well as our notbeing subject to a material amount of entity-level taxation by individualstates.  If the IRS were to treat us as acorporation for federal income tax purposes or we were to become subject to entity-leveltaxation for state tax purposes, taxes paid, if any, would reduce the amount ofcash available for distribution.***

 

The anticipatedafter-tax economic benefit of an investment in our units depends largely on ourbeing treated as a partnership for federal income tax purposes.  We have not requested, and do not plan torequest, a ruling from the IRS on this or any other tax matter that affects us.

 

If we were treatedas a corporation for federal income tax purposes, we would pay federal incometax on our taxable income at the corporate tax rates, currently at a maximumrate of 35%, and would likely pay state income tax at varying rates.  Distributions would generally be taxed againas corporate distributions, and no income, gain, loss, deduction or creditwould flow through to unitholders. Because a tax may be imposed on us as a corporation, our cash availablefor distribution to our unitholders could be reduced.  Therefore, treatment of us as a corporationwould result in a material reduction in the anticipated cash flow and after-taxreturn to our unitholders, likely causing a substantial reduction in the valueof our units.

 

Current law or ourbusiness may change so as to cause us to be treated as a corporation forfederal income tax purposes or otherwise subject us to entity-leveltaxation.  In addition, because ofwidespread state budget deficits and other reasons, several states areevaluating ways to subject partnerships and limited liability companies to entity-leveltaxation through the imposition of state income, franchise or other forms oftaxation.  For example, beginning in2008, we will be required to pay Texas franchise tax at a maximum effectiverate of 0.7% of our gross income apportioned to Texas in the prior year.  Imposition of such a tax on us by Texas and,if applicable, by any other state, will reduce the cash available fordistribution to our unitholders.

 

 

25

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**Item 1A****.****Risk Factors - Continued**

 

***Our unitholders mayhave more complex tax reporting and may be required to pay taxes on income evenif they do not receive any cash distributions from us.***

 

Our unitholdersare required to pay federal income taxes and, in some cases, state and localincome taxes on their share of our taxable income, whether or not they receivecash distributions from us.  Ourunitholders may not receive cash distributions from us equal to their share ofour taxable income or even equal to the actual tax liability that results fromtheir share of our taxable income. Furthermore, distributions to unitholders in excess of the total nettaxable income they were allocated, decreases their tax basis, which willbecome ordinary taxable income to them if the unit is later sold at a pricegreater than their tax basis, even if the price received is less than theiroriginal cost.

 

In addition tofederal income taxes, our unitholders will likely be subject to other taxes,including state and local taxes, unincorporated business taxes and estate,inheritance or intangible taxes that are imposed by the various jurisdictionsin which we do business or own property now or in the future, even if they donot reside in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and localincome tax returns and pay state and local income taxes in some or all of thesejurisdictions.  Further, our unitholdersmay be subject to penalties for failure to comply with those requirements.  In 2007, we have done business and ownedassets in West Virginia, Pennsylvania, New York, Virginia, California,Oklahoma, Kansas, New Mexico, Illinois, Indiana, and Texas.  As we make acquisitions or expand ourbusiness, we may do business or own assets in other states in the future.  It is the responsibility of each unitholderto file all United States federal, state and local tax returns that may berequired of such unitholder.  Our counselhas not rendered an opinion on the state or local tax consequences of aninvestment in our units.

 

**Item 1B.   Unresolved Staff Comments**

 

None.

 

 

26

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**Item 2.   ****Properties**

 

Informationconcerning proved reserves, production, wells, acreage and related matters arecontained in Part I. Item 1.  “Business andProperties.”

 

The Company’sobligations under its credit facility are secured by mortgages on its oil andgas properties.  See Part II.Item 7. “Management’s Discussion and Analysis of Financial Condition andResults of Operation” and Note 7 for additional information concerning thecredit facility.

 

***Offices***

 

The Company’s principalcorporate office is located at 600 Travis, Suite 5100, Houston, Texas77002.  The Company maintains additionaloffices in California, Kansas, Oklahoma, Pennsylvania, Texas and West Virginia.

 

**Item 3.     ****Legal Proceedings**

 

Although theCompany may, from time to time, be involved in litigation and claims arisingout of its operations in the normal course of business, the Company is notcurrently a party to any material legal proceedings.  In addition, the Company is not aware of anymaterial legal or governmental proceedings against it, or contemplated to bebrought against it, under the various environmental protection statutes towhich it is subject.

 

**Item 4.      Submission of Matters to a Vote ofSecurity Holders**

 

A special meetingof Company unitholders was held on November 1, 2007.  The matters voted on at the meeting and theresults are set forth below.

 

1.               To vote upon (a) a change in terms of the Company’sClass D units to provide that each Class D unit converts automaticallyinto a unit and (b) the issuance of 34,997,005 units upon such conversion.

 

| **Votes For** | ** ** | **Votes Against  or Withheld** | ** ** | **Abstentions** | ** ** |
|---------------|------------|--------------------------------|------------|-----------------|------------|
|          |       |                           |       |            |       |
| 48,064,105    |       | 106,238                        |       | 49,018          |       |

 

 

 

27

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**Part II**

 

**Item 5.   ****Market for Registrant’s Common Equity, Related Stockholder Matters andIssuer Purchases of Equity Securities**

 

**MarketInformation**

 

The Company’s units arelisted on The NASDAQ Global Select Market (“NASDAQ”) under the symbol “LINE”and began trading on January 13, 2006, after pricing of its initial publicoffering.  At the close of business on January 31,2008, there were approximately 411 unitholders of record.

 

The following presentsthe range of high and low last reported sales prices per unit, as reported byNASDAQ, for the quarters indicated.  Inaddition, distributions declared during each quarter are presented.

 
| ** **                         | ** ** | **Unit Price Range** | ** ** | **Cash  Distribution  Declared** | ** ** |
|------------------------------------|------------|----------------------|------------|----------------------------------|------------|
| **Quarter**                        | ** ** | **High**             | ** ** | **Low**                          | ** ** | **PerUnit** | ** ** |
| **2007:**                          | ** ** | ** **           | ** ** | ** **                       | ** ** | ** ** | ** ** |
| October 1 -  December 31 |       | $                    | 30.79      |                             | $          | 22.88 |   | $ | 0.57 |   |
| July 1 -  September 30   |       | $                    | 37.80      |                             | $          | 31.64 |   | $ | 0.57 |   |
| April 1 -  June 30       |       | $                    | 39.61      |                             | $          | 32.47 |   | $ | 0.52 |   |
| January 1 -  March 31    |       | $                    | 35.05      |                             | $          | 30.16 |   | $ | 0.52 |   |
| **2006:**                          |       |                 |       |                             |       |   |   |
| October 1 -  December 31 |       | $                    | 33.46      |                             | $          | 21.21 |   | $ | 0.43 |   |
| July 1 - September 30    |       | $                    | 24.10      |                             | $          | 20.08 |   | $ | 0.40 |   |
| April 1 -  June 30       |       | $                    | 21.00      |                             | $          | 18.72 |   | $ | 0.32 |   |
| January 13 -  March 31   |       | $                    | 22.35      |                             | $          | 19.55 |   | $ | — |   |

## ** **

## **Distributions**

## ** **

The Company’s limitedliability company agreement requires it to make quarterly distributions tountiholders of all “available cash.” Available cash means, for each fiscal quarter, all cash on hand at theend of the quarter less the amount of cash reserves established by the Board ofDirectors to:

 

                        ·      providefor the proper conduct of business (including reserves for future capitalexpenditures, future debt service requirements, and for anticipated creditneeds);

                        ·      complywith applicable laws, debt instruments or other agreements;

                        ·      plusall cash on hand on the date of determination of available cash for the quarterresulting from working capital borrowings made after the end of the quarter forwhich the determination is being made. Working capital borrowings are borrowings that will be made under theCompany’s credit facility and in all cases are used solely for working capitalpurposes or to pay distributions to unitholders.

 

See Part II.Item 7. “Management’s Discussion and Analysis of Financial Condition andResults of Operation - Liquidity and Capital Resources” for a discussionon the payment of future distributions.

 

 

28

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**Item 5.****          ****Market for Registrant’s Common Equity, Related Stockholder Matters andIssuer Purchases of Equity Securities -Continued**

 

**UnitholderReturn Performance Presentation**

 

The performancegraph below compares the total unitholder return on the Company’s units, withthe total return of the Standard & Poor’s 500 Index (the “S&P 500Index”) and the Alerian MLP Index, a weighted composite of 50 prominent energymaster limited partnerships.  Totalreturn includes the change in the market price, adjusted for reinvesteddividends or distributions, for the period shown on the performance graph andassumes that $100 was invested in the Company at the last reported sale priceof units as reported by NASDAQ ($22.00) on January 13, 2006 (the day tradingof the units commenced), and in the S&P 500 Index and the Alerian MLP Indexon the same date.  The results shown inthe graph below are not necessarily indicative of future performance.

 

 
| ** **        | ** ** | **January 13, 2006** | ** ** | **December 31, 2007** | ** ** |
|-------------------|------------|---------------------------|------------|----------------------------|------------|
|              |       |                      |       |                       |       |
| Linn Energy, LLC  |       | $100                      |       | $128(1)                    |       |
| Alerian MLP Index |       | $100                      |       | $136        |       |
| S&P 500 Index |       | $100                      |       | $118        |       |

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(1)              Based on the last reported sale price of the Company’sunits as reported by NASDAQ on December 31, 2007 ($25.03).

 

Notwithstandinganything to the contrary set forth in any of the Company’s previous or futurefilings under the Securities Act of 1933 or the Securities Exchange Act of 1934that might incorporate this Form 10-K or future filings with SEC, in wholeor in part, the preceding performance information shall not be deemed to be “solicitingmaterial” or to be “filed” with the SEC or incorporated by reference into anyfiling except to the extent this performance presentation is specificallyincorporated by reference therein.

 

**Securities Authorized for Issuance Under EquityCompensation Plans**

 

See theinformation incorporated by reference under Part III. Item 12. “SecurityOwnership of Certain Beneficial Owners and Management and Related StockholderMatters” regarding securities authorized for issuance under the Company’sequity compensation plans, which information is incorporated by reference intothis Item 5.

 

**Sales of Unregistered Securities**

 

None notpreviously reported on a Quarterly Report on Form 10-Q or a Current Reporton Form 8-K.  See Part II.Item 7. “Management’s Discussion and Analysis of Financial Condition andResults of Operation” for discussion of these matters.

 

 

29

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**Item 6.   ****Selected Financial Data**

 

The selectedfinancial data set forth below should be read in conjunction with Part II.Item 7. “Management’s Discussion and Analysis of Financial Condition andResults of Operation” and Item 8. “Financial Statements and Supplementary Data.”

 

Because of rapidgrowth through acquisitions and development of properties, the Company’shistorical results of operations and period-to-period comparisons of theseresults and certain other financial data may not be meaningful or indicative offuture results.

 
| ** **                                  | ** ** | **Year Ended December 31,**     | ** ** | **Period from  March 14, 2003  (Inception) - December 31,** | ** ** |
|---------------------------------------------|------------|--------------------------------------|------------|-----------------------------------------------------------------------|------------|
| ** **                                  | ** ** | **2007**                             | ** ** | **2006**                                                              | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                  | ** ** | **(dollars and units in thousands)** | ** ** |
| **Statement of operations data:**           | ** ** | ** **                           | ** ** | ** **                                                            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil, gas and NGL  sales                     |       | $                                    | 318,226    |                                                                  | $          | 80,393 |   | $ | 44,645 |   | $ | 19,502 |   | $ | 2,379 |   |
| Gain (loss) on  oil and gas derivatives (1) |       | (345,537                             | )          | 103,308                                                               |       | (76,193 | ) | (11,004 | ) | (1,437 | ) |
| Total revenues                              |       | (7,237                               | )          | 191,058                                                               |       | (26,481 | ) | 9,178 |   | 946 |   |
| Operating income  (loss)                    |       | (266,743                             | )          | 103,931                                                               |       | (48,864 | ) | (1,204 | ) | (1,197 | ) |
| Depreciation,  depletion and amortization   |       | 97,964                               |       | 24,173                                                                |       | 7,294 |   | 3,656 |   | 562 |   |
| Interest expense                            |       | 62,130                               |       | 25,857                                                                |       | 8,043 |   | 3,530 |   | 517 |   |
| Net income  (loss)                          |       | (364,349                             | )          | 79,185                                                                |       | (56,351 | ) | (4,816 | ) | (1,688 | ) |
| Net income  (loss) per unit — basic    |       | (5.29                                | )          | 2.64                                                                  |       | (2.75 | ) | (0.23 | ) | (0.06 | ) |
| Net income  (loss) per unit — diluted  |       | (5.29                                | )          | 2.61                                                                  |       | (2.75 | ) | (0.23 | ) | (0.06 | ) |
| Distributions  declared per unit            |       | 2.18                                 |       | 1.15                                                                  |       | — |   | — |   | — |   |
| Weighted average  units outstanding         |       | 68,916                               |       | 28,281                                                                |       | 20,518 |   | 20,518 |   | 27,813 |   |
| **Cash flow data:**                         | ** ** | ** **                           | ** ** | ** **                                                            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net cash  provided by (used in):            |       |                                 |       |                                                                  |       |   |   |   |   |   |   |
| Operating  activities (2)                   |       | $                                    | (44,814    | )                                                                     | $          | (6,805 | ) | $ | (29,518 | ) | $ | 10,351 |   | $ | (135 | ) |
| Investing  activities                       |       | (2,892,420                           | )          | (551,631                                                              | )          | (150,898 | ) | (61,373 | ) | (35,344 | ) |
| Financing  activities                       |       | 2,932,080                            |       | 553,990                                                               |       | 189,269 |   | 31,167 |   | 57,521 |   |
| Capital  expenditures                       |       | 2,896,958                            |       | 551,737                                                               |       | 150,849 |   | 63,594 |   | 32,863 |   |
| **Balance sheet data:**                     | ** ** | ** **                           | ** ** | ** **                                                            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Total assets                                |       | $                                    | 3,796,569  |                                                                  | $          | 905,912 |   | $ | 280,924 |   | $ | 105,425 |   | $ | 79,177 |   |
| Long-term debt                              |       | 1,443,830                            |       | 428,237                                                               |       | 207,695 |   | 72,750 |   | 41,518 |   |
| Unitholders’  capital (deficit)        |       | 2,026,641                            |       | 450,954                                                               |       | (46,831 | ) | 9,520 |   | 14,336 |   |
| **Operating data:**                         | ** ** | ** **                           | ** ** | ** **                                                            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Production:**                             | ** ** | ** **                           | ** ** | ** **                                                            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas (MMcf)                                  |       | 27,001                               |       | 8,599                                                                 |       | 4,720 |   | 3,110 |   | 304 |   |
| Oil (MBbls)                                 |       | 1,271                                |       | 370                                                                   |       | 20 |   | 10 |   | 31 |   |
| NGL (MBbls)                                 |       | 992                                  |       | —                                                                |       | — |   | — |   | — |   |
| Total (MMcfe)                               |       | 40,579                               |       | 10,818                                                                |       | 4,839 |   | 3,112 |   | 492 |   |
| Average daily  production (MMcfe/d)         |       | 111.2                                |       | 29.6                                                                  |       | 13.3 |   | 8.5 |   | 2.3 |   |
| **Estimated  Net Proved Reserves:**         | ** ** | ** **                           | ** ** | ** **                                                            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas (Bcf)                                   |       | 1,028.9                              |       | 274.0                                                                 |       | 191.9 |   | 118.9 |   | 68.9 |   |
| Oil (MMBbls)                                |       | 54.8                                 |       | 30.0                                                                  |       | 0.2 |   | 0.1 |   | 0.2 |   |
| NGL (MBbls)                                 |       | 43.1                                 |       | —                                                                |       | — |   | — |   | — |   |
| Total (Bcfe)                                |       | 1,616.1                              |       | 454.1                                                                 |       | 193.2 |   | 119.8 |   | 69.8 |   |
| **Total Weighted Average Prices:**          | ** ** | ** **                           | ** ** | ** **                                                            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Hedged (Mcfe) (3)                           |       | $                                    | 8.91       |                                                                  | $          | 9.79 |   | $ | 6.51 |   | $ | 5.55 |   | $ | 5.17 |   |
| Unhedged (Mcfe) (3)                         |       | $                                    | 7.84       |                                                                  | $          | 7.43 |   | $ | 9.23 |   | $ | 6.27 |   | $ | 4.84 |   |

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(1)              During 2005, the Company canceled (before theiroriginal settlement date) a portion of out-of-the-money gas swaps and realizeda loss of $38.3 million.  TheCompany subsequently hedged similar volumes at higher prices.  The remaining 2005 loss relates to losses onderivative positions settled in 2005 at scheduled maturity dates that were notrelated to the cancellation of out-of-the-money gas hedges.

 

(2)              Includes premiums paid for derivatives ofapproximately $279.3 million, $49.8 million and $1.6 million for the yearsended December 31, 2007, 2006 and 2005, respectively.

 

(3)              Hedged amounts include the effect ofrealized gains and losses on derivatives and unhedged amounts do not.

 

 

30

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**Item 7.    Management’s Discussion and Analysis of Financial Condition andResults of Operation**

 

*Thefollowing discussion and analysis should be read in conjunction with the “SelectedHistorical Consolidated Financial and Operating Data” and the financialstatements and related notes included elsewhere in this Annual Report on Form 10-K.  The following discussion contains forward-lookingstatements that reflect the Company’s future plans, estimates, beliefs andexpected performance.  Theforward-looking statements are dependent upon events, risks and uncertaintiesthat may be outside the Company’s control. The Company’s actual results could differ materially from thosediscussed in these forward-looking statements. Factors that could cause or contribute to such differences include, butare not limited to, market prices for oil, gas and NGL, production volumes,estimates of proved reserves, capital expenditures, economic and competitiveconditions, regulatory changes and other uncertainties, as well as thosefactors discussed below and elsewhere in this Annual Report on Form 10-K,particularly in Part I. Item 1A. “Risk Factors.” In light of theserisks, uncertainties and assumptions, the forward-looking events discussed maynot occur.*

 

A reference to a “Note”herein refers to the accompanying Notes to Consolidated Financial Statementscontained in Item 8. “Financial Statements and Supplementary Data.”

 

**Executive Summary**

 

Linn Energy is anindependent oil and gas company focused on the development and acquisition oflong life properties which complement its asset profile in producing basinswithin the United States.

 

Proved reserves atDecember 31, 2007 were 1,616.1 Bcfe, of which approximately 64% were gas,20% were oil and 16% were NGL. Approximately 73% were classified as proved developed, with a totalStandardized Measure value of $3.46 billion. At December 31, 2007, the Company operated 5,638, or 77%, of its7,305 gross productive wells.  Averageproved reserves-to-production ratio, or average reserve life, is approximately22 years, based on the December 31, 2007 reserve report and annualizedproduction for the fourth quarter ended December 31, 2007.

 

During the yearended December 31, 2007, the Company completed eight acquisitions ofworking and royalty interests in oil and gas properties.  In January 2008, the Company completedtwo additional acquisitions of oil and gas properties.  On a pro forma basis, including these twoacquisitions, total proved reserves at December 31, 2007 were 1,945.5Bcfe, of which approximately 55% were gas, 32% were oil and 13% were NGL.

 

***Acquisitions***

 

The followingprovides a summary of acquisitions of working and royalty interests the Companyhas completed from January 1, 2007 through the date of this report:

 
| **Date**           | ** ** | **Gross  Wells****(1)** | ** ** | **Operating Region** | ** ** | **Aggregate  Contract Price** | ** ** |
|--------------------|------------|-------------------------|------------|----------------------|------------|-------------------------------|------------|
| ** **         | ** ** | ** **              | ** ** | ** **           | ** ** | **(in millions)**             | ** ** |
|               |       |                    |       |                 |       |                          |       |
| January 2007  |       | 51                      |       | Appalachian Basin    |       | $                             | 33.0       |   |
| February 2007 |       | 4                       |       | Appalachian Basin    |       | 5.9                           |       |
| February 2007 |       | 851                     |       | Mid-Continent        |       | 415.0                         |       |
| April 2007    |       | 300                     |       | Western              |       | 10.0                          |       |
| June 2007     |       | 514                     |       | Mid-Continent        |       | 90.5                          |       |
| August 2007   |       | 2,685                   |       | Mid-Continent        |       | 2,050.0                       |       |
| October 2007  |       | 100                     |       | Mid-Continent        |       | 22.5                          |       |
| October 2007  |       | —                  |       | Mid-Continent        |       | 52.0                          |       |
| January 2008  |       | 2,312                   |       | Mid-Continent        |       | 552.2                         |       |
| January 2008  |       | 138                     |       | Appalachian Basin    |       | 14.7                          |       |
|               |       | 6,955                   |       |                 |       | $                             | 3,245.8    |   |

 

----

(1)              Grosswells do not include approximately 1,800 wells associated with royalty interestacquisitions.

 

From inceptionthrough the date of this report, the Company has completed 24 acquisitions ofworking and royalty interests in oil and gas properties and related gatheringand pipeline assets.  Total acquiredproved 

 

31

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**Item7.    Management’s Discussion and Analysisof Financial Condition and Results of Operation****-****Continued**

 

reserves wereapproximately 1.9 Tcfe at an acquisition cost of approximately $2.11 perMcfe.  See Note 2 for additionaldetails about the Company’s acquisitions.

 

The Company finances acquisitions with a combination of proceeds fromthe issuance of its units, bank borrowings and cash flow from operations. During 2007, the Company completed three private placements of itsunits, with gross proceeds of $2.12 billion. During 2006, the Company completed one additional private placement,with gross proceeds of $305.0 million. See “Private Placements” below and also Note 4 for additionaldetails about the Company’s private placement of units.

 

***Private Placements***

 

During 2007 and 2006, the Company closed four private placements ofunits to groups of institutional investors.

 
| **Date Issued**         | ** ** | **Gross Proceeds** | ** ** | **Units Issued** | ** ** | **Date Converted  to Units****(1)** | ** ** | **Date Registered  With SEC** | ** **         | **Date Lock-Up  Expired****(2)** | ** **             |
|-------------------------|------------|--------------------|------------|------------------|------------|-------------------------------------|------------|-------------------------------|--------------------|----------------------------------|------------------------|
| ** **              | ** ** | **(in thousands)** | ** ** | ** **       | ** ** | ** **                          | ** ** | ** **                    | ** **         | ** **                       | ** **             |
| **August 2007:**   | ** ** | ** **         | ** ** | ** **       | ** ** | ** **                          | ** ** | ** **                    | ** **         | ** **                       | ** **             |
| Units                   |       | $                  | 416,000    |             | 12,999,989 |                                |       |                          | December 2007 |                             | February 14, 2008 |   |
| D Units                 |       | 1,084,000          |       | 34,997,005       |       | November 2007                  |       | December 2007            |               | February 14, 2008           |                   |
| ** **              |       | $                  | 1,500,000  |             | 47,996,994 |                                |       |                          |               |                             |                   |   |
| **June 2007:**     | ** ** | ** **         | ** ** | ** **       | ** ** | ** **                          | ** ** | ** **                    | ** **         | ** **                       | ** **             |
| Units                   |       | $                  | 260,000    |             | 7,761,194  |                                |       |                          | December 2007 |                             | February 14, 2008 |   |
| ** **              | ** ** | ** **         | ** ** | ** **       | ** ** | ** **                          | ** ** | ** **                    | ** **         |                             | ** **             |
| **February 2007:** | ** ** | ** **         | ** ** | ** **       | ** ** | ** **                          | ** ** | ** **                    | ** **         | ** **                       | ** **             |
| Units                   |       | $                  | 172,904    |             | 6,650,144  |                                |       |                          | December 2007 |                             | December 14, 2007 |   |
| C Units                 |       | 187,096            |       | 7,465,946        |       | April 2007                     |       | December 2007            |               | December 14, 2007           |                   |
| ** **              |       | $                  | 360,000    |             | 14,116,090 |                                |       |                          |               |                             |                   |   |
| **October 2006:**  | ** ** | ** **         | ** ** | ** **       | ** ** | ** **                          | ** ** | ** **                    | ** **         | ** **                       | ** **             |
| Units                   |       | $                  | 116,228    |             | 5,534,687  |                                |       |                          | December 2007 |                             | December 14, 2007 |   |
| B Units                 |       | 188,772            |       | 9,185,965        |       | January 2007                   |       | December 2007            |               | December 14, 2007           |                   |
|                    |       | $                  | 305,000    |             | 14,720,652 |                                |       |                          |               |                             |                   |   |

----

(1)              Notapplicable for units.

 

(2)              Lock-upexpiration date represents date investors were allowed to sell or transferunits per terms of purchase agreements.

 

The proceeds from the private placements, net of expenses, were used tofinance acquisitions and to repay indebtedness under the Company’s creditfacility.  See Note 4 for additionaldetails about the private placements.

 

***Operating Regions***

 

The Company’s oil,gas and NGL properties are currently located in three regions in the UnitedStates:

 

·                  Mid-Continent, which includes the core operating areas Texas Panhandleand Oklahoma;

·                  Appalachian Basin, which includes fields in West Virginia andPennsylvania; and

·                  Western, which includes the Brea Olinda Field of the Los Angeles Basinin California.

 

***Mid-Continent***

 

**The Mid-Continent is the Company’s largest region, and as noted above,includes two key core operating areas. First, the Texas Panhandle area, which consists of shallow oil and gasproduction from the Brown Dolomite formation at depths of approximately 3,200feet and the Deep Granite Wash formation which produces at depths ranging from8,900 feet to 16,000 feet. **This area produced 71.6 MMcfe/d, or 36%, of theCompany’s fourth quarter 2007 production. **Thesecond core area is located primarily in Oklahoma.  Producing depths range from 6,000 feet**

 

 

32

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**Item7.    Management’s Discussion and Analysisof Financial Condition and Results of Operation****-****Continued**

 

**to 20,000 feet in this area. **This area produced 92.7 MMcfe/d, or 46%,of the Company’s fourth quarter 2007 production.  During 2007, the Company investedapproximately $40.0 million to drill in Oklahoma.

 

In order to moreefficiently transport its gas to market, the Company owns and operates anetwork of gas gathering systems comprised of approximately 800 miles ofpipeline and associated compression and metering facilities which connect tonumerous sales outlets in the Texas Panhandle.

 

***Appalachian Basin***

 

The AppalachianBasin includes fields in West Virginia and Pennsylvania.  This region produced 24.3 MMcfe/d, or 12%, ofthe Company’s fourth quarter 2007 production. During 2007, the Company invested approximately $34.3 million to drillin the Appalachian Basin.  The proximityof the Company’s properties in this region to major United States consumingmarkets allows the Company to receive premium pricing on this production.

 

The Company alsoperforms limited gas gathering activities for others on non-jurisdictionalgathering systems, primarily in Pennsylvania. The Company aggregates these volumes with production and sells all thegas through meters to the same purchasers. These revenues are collected and distributed to the third partyproducers in the normal course of business.

 

***Western***

 

Western consistsof the Brea Olinda Field of the Los Angeles Basin in California.  The Brea Olinda Field was discovered in 1880and produces from the shallow Pliocene formation to the deeper Mioceneformation.  This region produced 11.6MMcfe/d, or 6%, of the Company’s fourth quarter 2007 production.  During 2007, the Company investedapproximately $2.4 million to drill in this region.

 

The Western region alsoincludes the operation of a gas processing facility which processes producedgas from Company and third party wells.  Processed gas is utilized togenerate electricity which is used in the field to power equipment, resultingin reduced operating costs.  Revenues arealso generated from the sale of excess power.

 

 

33

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**Item 7.    Management’sDiscussion and Analysis of Financial Condition and Results of Operation****-****Continued**

 

**Results of Operations - Year Ended December 31,2007 Compared to Year Ended December 31, 2006**

 

The followingprovides selected financial and operating data for the years indicated:

 
| ** **                                | ** ** | **Year Ended December 31,** | ** ** | ** ** | ** ** |
|-------------------------------------------|------------|----------------------------------|------------|------------|------------|
| ** **                                | ** ** | **2007**                         | ** ** | **2006**   | ** ** | **Variance** | ** ** |
| ** **                                | ** ** | **(in thousands)**               | ** ** |
| **Revenues:**                             | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas sales                                 |       | $                                | 178,627    |       | $          | 61,641 |   | $ | 116,986 |   |
| Oil sales                                 |       | 84,538                           |       | 18,752     |       | 65,786 |   |
| NGL sales                                 |       | 55,061                           |       | —     |       | 55,061 |   |
| Total oil, gas  and NGL sales             |       | 318,226                          |       | 80,393     |       | 237,833 |   |
| Gain (loss) on  oil and gas derivatives   |       | (345,537                         | )          | 103,308    |       | (448,845 | ) |
| Natural gas  marketing revenues           |       | 15,537                           |       | 5,598      |       | 9,939 |   |
| Other revenues                            |       | 4,537                            |       | 1,759      |       | 2,778 |   |
| Total revenues                            |       | $                                | (7,237     | )          | $          | 191,058 |   | $ | (198,295 | ) |
| **Expenses:**                             | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Operating  expenses                       |       | $                                | 88,527     |       | $          | 18,099 |   | $ | 70,428 |   |
| Natural gas  marketing expenses           |       | 12,596                           |       | 4,862      |       | 7,734 |   |
| General and  administrative expenses      |       | 57,188                           |       | 39,993     |       | 17,195 |   |
| Data license  expenses                    |       | 3,231                            |       | —     |       | 3,231 |   |
| Depreciation,  depletion and amortization |       | 97,964                           |       | 24,173     |       | 73,791 |   |
| Total expenses                            |       | $                                | 259,506    |       | $          | 87,127 |   | $ | 172,379 |   |
| **Other income and (expenses)**           |       | $                                | (94,033    | )          | $          | (28,148 | ) | $ | (65,885 | ) |

 
| ** **                                     | ** ** | **Year Ended December 31,** | ** ** | ** ** | ** ** |
|------------------------------------------------|------------|----------------------------------|------------|------------|------------|
| ** **                                     | ** ** | **2007**                         | ** ** | **2006**   | ** ** | **Variance** | ** ** |
| **Production:**                                | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas production  (MMcf)                         |       | 27,001                           |       | 8,599      |       | 214.0 | % |
| Oil production  (MBbls)                        |       | 1,271                            |       | 370        |       | 243.5 | % |
| NGL production  (MBbls)                        |       | 992                              |       | —     |       | — |   |
| Total production  (MMcfe)                      |       | 40,579                           |       | 10,818     |       | 275.1 | % |
| Average daily  production (MMcfe/d)            |       | 111.2                            |       | 29.6       |       | 275.7 | % |
| ** **                                     | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Weighted average prices (hedged):****(1)**   | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas (Mcf)                                      |       | $                                | 8.19       |       | $          | 9.79 |   | (16.3 | )% |
| Oil (Bbl) (2)                                  |       | $                                | 66.15      |       | $          | 58.68 |   | 12.7 | % |
| NGL (Bbl)                                      |       | $                                | 56.75      |       | $          | — |   | — |   |
| ** **                                     | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Weighted average prices (unhedged):****(3)** | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas (Mcf)                                      |       | $                                | 6.62       |       | $          | 7.17 |   | (7.7 | )% |
| Oil (Bbl) (2)                                  |       | $                                | 66.51      |       | $          | 50.68 |   | 31.2 | % |
| NGL (Bbl)                                      |       | $                                | 55.51      |       | $          | — |   | — |   |
| ** **                                     | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Average unit costs per Mcfe of production:** | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Operating  expenses                            |       | $                                | 2.18       |       | $          | 1.67 |   | 30.5 | % |
| General and  administrative expenses (4)       |       | $                                | 1.41       |       | $          | 3.70 |   | (61.9 | )% |
| Depreciation,  depletion and amortization      |       | $                                | 2.41       |       | $          | 2.23 |   | 8.1 | % |

----

(1)              Includes the effect of realized gains of$43.2 million and $25.5 million on derivatives for the years ended December 31,2007 and 2006, respectively.

 

(2)              Oil production in California is soldpursuant to a long-term contract at 79% of NYMEX, and with gravity increase dueto NGL being mixed into the oil stream, prices realized average approximately82% of NYMEX.

 

(3)              Does not include the effect of realizedgains on derivatives.

 

(4)              The measure for the years ended December 31,2007 and 2006 includes approximately $13.9 million and $21.6 million,respectively, of unit-based compensation and unit warrant expense.  The year ended December 31, 2006 alsoincludes approximately $2.0 million of IPO bonuses.  Excluding these amounts, general andadministrative expenses for the years ended December 31, 2007 and 2006were $1.07 per Mcfe and $1.51 per Mcfe, respectively.  This is a non-GAAP measure used by Companymanagement to analyze its performance.

 

 

34

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**Item 7.    Management’s Discussion and Analysis of Financial Condition andResults of Operation****-****Continued**

 

***Revenues***

 

Gas, oil andNGL sales increased 296%, to approximately$318.2 million for the year ended December 31, 2007, from $80.4 millionfor the year ended December 31, 2006.

 

The increase in revenue from gas, oil and NGL sales was primarilyattributable to increased production as a result of acquisitions anddrilling.  Total production increased to40,579 MMcfe during the year ended December 31, 2007, from 10,818 MMcfeduring the year ended December 31, 2006. The increase in production was due primarily to production from oil andgas properties acquired during 2007 and 2006 and by the drilling of newwells.  The Company drilled 253 wellsduring 2007, compared to 159 wells during 2006.

 

Gas production increased to 27,001 MMcf during the year ended December 31,2007, from 8,599 MMcf during the year ended December 31, 2006, with the2007 acquisitions in the Mid-Continent region (see Note 2) contributingapproximately 15,734 MMcf from the respective closing dates of theacquisitions.  The increase in productionwas slightly offset by a reduction in the weighted average gas price, from$7.17 per Mcf during the year ended December 31, 2006, to $6.62 per Mcfduring the year ended December 31, 2007, which caused gas revenues todecrease approximately $4.8 million.

 

Oil production increased to 1,271 MBbls during the year ended December 31,2007, from 370 MBbls during the year ended December 31, 2006, due to theacquisitions in the Western and Mid-Continent regions.  The acquisitions in the Mid-Continent alsoincreased NGL production to 992 MBbls during the year ended December 31,2007, from zero during the comparative period of the prior year.  The increase in the weighted average price ofoil for the period, from $50.68 per Bbl to $66.51 per Bbl, contributedapproximately $5.9 million to the increase in oil revenues.

 

***Hedging Activities***

 

During the year ended December 31, 2007, the Company had commoditypricing derivative contracts for approximately 82% of its gas production and86% of its oil and NGL production, which resulted in realized gains of $43.2million (greater revenues than would have been achieved at unhedgedprices).  During the year ended December 31,2006, the Company had approximately 108% of its gas production and 50% of itsoil production hedged, which resulted in realized gains of $25.5 million.  Unrealized losses on derivatives in theamount of $388.7 million for the year ended December 31, 2007, andunrealized gains of $77.8 million for the year ended December 31, 2006,were also recorded.  Unrealized gains andlosses result from changes in market valuations of derivatives as futurecommodity price expectations change compared to the contract price on thederivative.  During 2007, expected future oil and gas pricesincreased, which reduced the market value of the derivatives.  Such market value adjustment, if realized inthe future, would be offset by higher actual prices for production.  Since the Company has hedged a significantportion of its oil and gas production at fixed prices, it may not realize thebenefit of future increases in commodity prices.  However, the Company utilizes put contractsas a significant percentage of its hedging portfolio.  Puts not only protect against declines incommodity prices, but also preserve commodity upside.  See Note 9 for details regardingderivatives in place through December 31, 2013.

 

***Expenses***

 

Operating expenses, which include expenses such as lease operating,labor, field office, vehicle, supervision, transportation, maintenance, tools,supplies, and production and ad valorem taxes, increased to $88.5 million forthe year ended December 31, 2007, from $18.1 million for the year ended December 31,2006.  Production taxes, which are afunction of volumes and revenues generated from production, increased to $17.8million for the year ended December 31, 2007, from $2.0 million in2006.  Ad valorem taxes, which are basedon the value of reserves and vary by location, increased to $8.2 million forthe year ended December 31, 2007, from $1.6 million in 2006.  Operating expenses also increased due tocosts associated with the 2007 acquisitions in the Mid-Continent region,including expenses associated with the addition of approximately 150 field anddirect field support employees.  Inaddition, the number of producing wells, which increased by over 4,000 grosswells as a result of the acquisitions completed in 2007 and the drilling of 253wells during the year ended December 31, 2007, and 612 wells frominception through December 31, 2007, also contributed to the increasedoperating expenses.

 

 

35

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**Item 7.    Management’s Discussion and Analysis of Financial Condition andResults of Operation****-****Continued**

 

Average operating expenses per equivalent unit of production increasedto $2.18 for the year ended December 31, 2007, compared to $1.67 for theyear ended December 31, 2006. Operating expenses per Mcfe increased due to material and labor costsand the changing mix of production beginning in the third quarter of 2006 toinclude oil and NGL, which have higher operating costs than gas wells.  During 2007, the Company also incurred costsfor workover and maintenance of its wells to enhance future production and/oroffset decline. Operating expenses per Mcfe also increased by $0.09 due toturnover of purchased inventory valued at acquisition cost instead of cost toproduce.

 

General and administrative expenses include the costs of employees andexecutive officers, related benefits, office leases, professional fees andother costs not directly associated with field operations.  General and administrative expenses increasedto approximately $57.2 million for the year ended December 31, 2007, from$40.0 million for the year ended December 31, 2006.  The increase in general and administrative expenseswas primarily due to costs incurred to support the Company’s rapid growththrough acquisitions and position the Company for future growth.  In conjunction with expansion and developmentof the organization during 2007, the Company hired approximately 150 employees(including approximately 100 corporate, administrative and support employeeswith the Mid-Continent acquisition) and as a result, salaries and benefitsexpense increased approximately $13.5 million over 2006.  Costs to perform the necessary functionsassociated with being a growing company were $14.2 million during 2007,compared to $6.1 million during 2006. These costs include expenses for recruitment of key management teammembers, acquisition related data conversion and integration, publicpartnership tax reporting, audit fees, legal fees, proxy and printing costs andother professional fees, including costs related to compliance with Section 404of the Sarbanes-Oxley Act of 2002.  Inaddition, acquisition costs that are not eligible for capitalization, includinginternal and indirect costs for completed acquisitions, as well as direct costsassociated with acquisition efforts that have not reached fruition, contributedto the increase.  The increase in generaland administrative expenses was partially offset by lower employee unit-basedcompensation expense, which decreased to $9.5million (exclusive of amounts associated with certain of the newemployees) during the year ended December 31, 2007, from $21.6 million during 2006.  Unit-based compensation expense incurredduring the year ended December 31, 2006 was higher compared to thatincurred in 2007, primarily due to expense associated with unit awards grantedin conjunction with the Company’s IPO in January 2006.  General and administrative expenses arepresented net of approximately $0.9 millionand $1.1 million during the years ended December 31,2007 and 2006, respectively, which represent expense reimbursements fromother working interest owners.

 

The Companyincurred expenses of approximately $3.2 million for initial, one-time datalicense fees during the year ended December 31, 2007.  These expenses primarily represent fees for accessto 3-D seismic and other data libraries in the Mid-Continent to enable theCompany to maximize drilling opportunities in that region.

 

Depreciation,depletion and amortization increased to approximately$98.0 million for the year ended December 31, 2007, from $24.2 million forthe year ended December 31, 2006. Of this increase, approximately $37.9million was as a result of depletion related to the Mid-Continentacquisition in August 2007.  Theproperties acquired in the Mid-Continent acquisitions earlier in 2007contributed approximately $12.4 million to the increase.  Although total depreciation, depletion andamortization increased during 2007 due to higher total production levels, thereserves in the acquired Texas, Oklahoma and California properties have lowerdepletion rates than the reserves in the Appalachian Basin.  Depreciation, depletion and amortizationexpenses include impairment expense of $3.3 million and $1.0 million for theyears ended December 31, 2007 and 2006, respectively.

 

Other income and(expenses) increased to a net expense of $94.0million for the year ended December 31,2007, compared to a net expense of $28.1million for the year ended December 31,2006, primarily due to increased interest expense from increased debtlevels associated with borrowings to fund the Mid-Continent acquisition anddrilling.  Cash payments for interestincreased to $57.3 million for theyear ended December 31, 2007,compared to $24.1 million for theyear ended December 31, 2006.  The Company’s interest rate swaps were notdesignated as cash flow hedges under SFAS No. 133, “*Accounting for Derivative Instruments and HedgingActivities,”* as amended, (“SFAS 133”), even though they reduceexposure to changes in interest rates (see Note 8).  Therefore, the changes in fair values ofthese instruments were recorded as a loss of approximately $29.5 million and a gain of approximately $82,000 forthe years ended December 31, 2007 and2006, respectively.  These amountsare non-cash items.

 

 

36

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**Item7.    Management’s Discussion and Analysisof Financial Condition and Results of Operation****-****Continued**

 

Income tax was an expense of approximately $3.6 million for the year ended December 31, 2007 and a benefit ofapproximately $3.4 million for the year ended December 31, 2006.  The Company is a limited liability companytreated as a partnership for federal and state income tax purposes.  Certain of the Company’s subsidiaries areSubchapter C-corporations subject to corporate income taxes.  The Company’s taxable subsidiaries generatednet operating losses for the year ended December 31, 2006.  Management has subsequently recoveredexpenses through an intercompany charge for services from Linn Operating, Inc.to Linn Energy, which resulted in a corresponding tax expense in the year endedDecember 31, 2007.

 

37

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**Item7.    Management’s Discussion and Analysisof Financial Condition and Results of Operation****-****Continued**

 

**Resultsof Operations - Year Ended December 31, 2006 Compared to Year Ended December 31,2005**

 

The followingprovides selected financial and operating data for the years indicated:

 
| ** **                                      | ** ** | **Year Ended December 31,** | ** ** | ** **          | ** ** |
|-------------------------------------------------|------------|----------------------------------|------------|---------------------|------------|
| ** **                                      | ** ** | **2006**                         | ** ** | **2005**            | ** ** | **Variance** | ** ** |
|                                            |       |                             |       | **(in  thousands)** |       |   |   |
| **Revenues:**                                   | ** ** | ** **                       | ** ** | ** **          | ** ** | ** ** | ** ** |
| Gas sales                                       |       | $                                | 61,641     |                | $          | 43,594 |   | $ | 18,047 |   |
| Oil sales                                       |       | 18,752                           |       | 1,051               |       | 17,701 |   |
| Total oil and  gas sales                        |       | 80,393                           |       | 44,645              |       | 35,748 |   |
| Gain (loss) on  oil and gas derivatives **(1)** |       | 103,308                          |       | (76,193             | )          | 179,501 |   |
| Natural gas  marketing revenues                 |       | 5,598                            |       | 4,722               |       | 876 |   |
| Other revenues                                  |       | 1,759                            |       | 345                 |       | 1,414 |   |
| Total revenues                                  |       | $                                | 191,058    |                | $          | (26,481 | ) | $ | 217,539 |   |
| **Expenses:**                                   | ** ** | ** **                       | ** ** | ** **          | ** ** | ** ** | ** ** |
| Operating  expenses                             |       | $                                | 18,099     |                | $          | 7,356 |   | $ | 10,743 |   |
| Natural gas  marketing expenses                 |       | 4,862                            |       | 4,401               |       | 461 |   |
| General and  administrative expenses            |       | 39,993                           |       | 3,332               |       | 36,661 |   |
| Depreciation,  depletion and amortization       |       | 24,173                           |       | 7,294               |       | 16,879 |   |
| Total expenses                                  |       | $                                | 87,127     |                | $          | 22,383 |   | $ | 64,744 |   |
| **Other income and (expenses)**                 |       | $                                | (28,148    | )                   | $          | (7,413 | ) | $ | (20,735 | ) |

 
| ** **                                     | ** ** | **Year Ended December 31,** | ** ** | ** ** | ** ** |
|------------------------------------------------|------------|----------------------------------|------------|------------|------------|
| ** **                                     | ** ** | **2006**                         | ** ** | **2005**   | ** ** | **Variance** | ** ** |
| **Production:**                                | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas production  (MMcf)                         |       | 8,599                            |       | 4,720      |       | 82.2 | % |
| Oil production  (MBbls)                        |       | 370                              |       | 20         |       | 1750.0 | % |
| Total production  (MMcfe)                      |       | 10,818                           |       | 4,839      |       | 123.6 | % |
| Average daily  production (MMcfe/d)            |       | 29.6                             |       | 13.3       |       | 122.6 | % |
| ** **                                     | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Weighted average prices (hedged):****(1)**   | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas (Mcf)                                      |       | $                                | 9.79       |       | $          | 6.45 |   | 51.8 | % |
| Oil (Bbl) **(2)**                              |       | $                                | 58.68      |       | $          | 52.55 |   | 11.7 | % |
| ** **                                     | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Weighted average prices (unhedged):****(3)** | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Gas (Mcf)                                      |       | $                                | 7.17       |       | $          | 9.24 |   | (22.4 | )% |
| Oil (Bbl) **(2)**                              |       | $                                | 50.68      |       | $          | 52.55 |   | (3.6 | )% |
| ** **                                     | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Average unit costs per Mcfe of production:** | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Operating  expenses                            |       | $                                | 1.67       |       | $          | 1.52 |   | 9.9 | % |
| General and  administrative expenses**(4)**    |       | $                                | 3.70       |       | $          | 0.69 |   | 436.2 | % |
| Depreciation,  depletion and amortization      |       | $                                | 2.23       |       | $          | 1.51 |   | 47.7 | % |

----

**(1)**              During the yearended December 31, 2005, the Company cancelled (before the originalsettlement date) a portion of out-of-the money gas swaps and realized a loss of$38.3 million.  The Company subsequentlyhedged similar volumes at higher prices. Weighted average prices (hedged), include the effect of realized gainsof $25.5 million and realized losses $13.1 million (excluding the $38.3 millionloss) on derivatives for the years ended December 31, 2006 and 2005,respectively.

 

**(2)**              Oil production inCalifornia is sold pursuant to a long-term contract at 79% of NYMEX, and withgravity increase due to NGL being mixed into the oil stream, prices realizedaverage approximately 82% of NYMEX.

 

**(3)**              Does not include theeffect of realized gains on derivatives.

 

**(4)**              The measure for theyear ended December 31, 2006 includes approximately $21.6 million ofunit-based compensation expense and approximately $2.0 million of IPObonuses.  Excluding these amounts,general and administrative expenses for the year ended December 31, 2006was $1.51 per Mcfe.  This is a non-GAAPmeasure used by Company management to analyze its performance.

 

38

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**Item7.    Management’s Discussion and Analysisof Financial Condition and Results of Operation****-****Continued**

 

***Revenues***

 

Oil and gas salesincreased to approximately $80.4 million for the year ended December 31,2006, from $44.6 million for the year ended December 31, 2005.

 

The increase inrevenue from oil and gas sales was primarily attributable to increasedproduction.  Total production increasedto 10,818 MMcfe during the year ended December 31, 2006, from 4,839 MMcfeduring the year ended December 31, 2005. Oil production increased to 370 MBbls during the year ended December 31,2006, from 20 MBbls during the year ended December 2005, primarily due tothe acquisition of Blacksand in August 2006.  Gas production increased to 8,599 MMcf duringthe year ended December 31, 2006, from 4,720 MMcf during the year ended December 31,2005.  The increase in gas production wasdue to the drilling of new wells and production added by the acquisitions ofoil and gas properties during 2006 and 2005. The company drilled 159 wells during 2006 and 110 wells in 2005.

 

***Hedging Activities***

 

During the year ended December 31, 2006, the Company entered intocommodity pricing derivative contracts for approximately 108% of gas productionand 50% of oil production, which resulted in revenues that were $25.5 milliongreater than the Company would have achieved at unhedged prices.  During the year ended December 31, 2005,the Company entered into commodity pricing derivative contracts forapproximately 84% of oil and gas production, which resulted in revenues thatwere $13.1 million less than the Company would have achieved at unhedgedprices.  During the year ended December 31,2005, the Company canceled (before its original settlement date) a portion ofout-of-the-money gas hedges and realized a loss of $38.3 million, thensubsequently hedged similar volumes at higher prices.  Unrealized gain on derivatives in the amountof $77.8 million for the year ended December 31, 2006 and unrealizedlosses on derivatives in the amounts of $24.8 million for the year ended December 31,2005 were also recorded.  Unrealizedgains and losses result from oil and gas price fluctuations as compared to thesettlement price on the derivative.

 

***Expenses***

 

Operating expensesinclude expenses such as lease operating,labor, field office, vehicle, supervision, transportation, maintenance, tools,supplies, and production and ad valorem taxes.  Production taxes are a function of volumesand revenues generated from production. Ad valorem taxes vary by location and are based on the value ofreserves.  Operating expenses increasedto $18.1 million for the year ended December 31, 2006, from $7.4 millionfor the year ended December 31, 2005, due to the increase in the number ofproducing wells as a result of the acquisitions completed in both 2006 and 2005and the drilling of 159 wells during 2006 and 110 wells during 2005.  From inception through December 31,2006, the Company drilled 359 wells and acquired 3,344 wells.

 

General andadministrative expenses include the costs of employees and executive officers,related benefits, office leases, professional fees and other costs not directlyassociated with field operations. General and administrative expenses increased to $40.0 million, for theyear ended December 31, 2006, from $3.3 million for the year ended December 31,2005.  The increase in general andadministrative expenses was due to the recognition of unit-based compensationexpense of $21.6 million during the year ended December 31, 2006, comparedto none during the year ended December 31, 2005.  In addition, acquisition costs that are noteligible for capitalization, including internal and indirect costs forcompleted acquisitions, as well as direct costs associated with acquisitionefforts that have not reached fruition, contributed to the increase.  Costs to support rapidly growing operationsand position the Company for future growth include increasing staffing levelsto manage the 359 wells drilled and 3,344 wells acquired from inception in 2003through December 31, 2006, recruiting key management team members andperforming the functions associated with being a public company, which totaledapproximately $6.1 million in 2006 (the year of IPO).  General and administrative expenses arepresented net of approximately $1.1 million and $1.2 million during the yearended December 31, 2006 and 2005, respectively, which represent expensereimbursements from other working interest owners.

 

39

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**Item7.    Management’s Discussion and Analysisof Financial Condition and Results of Operation****-****Continued**

 

Depreciation, depletion and amortization increased to $24.2 million forthe year ended December 31, 2006, from $7.3 million for the year ended December 31,2005.  Of this increase, approximately$4.8 million was as a result of depletion related to the properties that wereacquired in the Western and Mid-Continent regions in the third quarter of 2006.  In addition, the depletion rate for oil andgas properties in the Appalachia Basin increased 37.4% in the fourth quarter of2006, due to a downward revision of estimated reserves from the prior year.  The Company also recorded $1.0 million ofimpairments during the year ended December 31, 2006.

 

Other income and(expenses) increased to a net expense of $28.1 million for the year ended December 31,2006, compared to a net expense of $7.4 million for the year ended December 31,2005, primarily due to increased debt levels associated with acquisitions anddrilling.  Cash payments for interestincreased to $24.1 million for the year ended December 31, 2006, from $6.5million for the year ended December 31, 2005.  Interest rate swaps were not designated as cashflow hedges under SFAS 133, even though they reduce exposure to changes ininterest rates.  Therefore, the changesin fair values of these instruments were recorded as gains of approximately$82,000 and $1.0 million for the years ended December 31, 2006 and 2005,respectively.  These amounts are non-cashgains.

 

Income tax was abenefit of approximately $3.4 million for the year ended December 31,2006.  Income tax expense wasapproximately $74,000 for the year ended December 31, 2005.  Linn Energy is a limited liability company,and is taxed substantially as a partnership; however, the Company’s taxablesubsidiaries generated net operating losses for the year ended December 31,2006.  The increase in realizable netoperating loss income tax benefit currently realizable was the result of a 2006backlog of expenses reported by the taxable subsidiaries on behalf of theconsolidated Company.  Such losses wererealized in 2007 since the strategy of the corporate structure for the taxablesubsidiaries is to recover costs rather than generate significant profits andthe forecast of loss generation is not expected to turn around in theforeseeable future.

 

**Liquidityand****Capital Resources**

 

The Company has utilized public and privateequity, proceeds from bank borrowings and cash flow from operations for capitalresources and liquidity.  To date, theprimary use of capital has been for the acquisition and development of oil andgas properties. The Company manages its working capital and cash requirementsto borrow only as needed from its credit facility. At December 31, 2007, theCompany’s total current liabilities exceeded current assets by $59.6 milliondue to a $65.3 million current payable for post-closing settlement costs for anoil and gas acquisition. The Company has $354.5 in available borrowing to meetsuch obligations at December 31, 2007.

 

As the Company pursues growth, itcontinually monitors the capital resources available to meet future financialobligations and planned capital expenditures. The Company’s future success in growing reserves and production will behighly dependent on the capital resources available and its success in drillingfor or acquiring additional reserves. The Company actively reviews acquisition opportunities on an ongoingbasis.  If the Company were to makesignificant additional acquisitions for cash, it would need to borrowadditional amounts under the credit facility, if available, or obtainadditional debt or equity financing.  Thecredit facility imposes certain restrictions on the Company’s ability to obtainadditional debt financing.  Based uponcurrent expectations, the Company believes liquidity and capital resources willbe sufficient for the conduct of its business and operations.

 

***Statementsof Cash Flows — Operating Activities***

 

At December 31, 2007, theCompany had $1.4 million cash and cash equivalents compared to $6.6 million at December 31,2006.  Cash used by operating activitiesfor the year ended December 31, 2007 was approximately $44.8 million,compared to cash provided by operating activities of $6.8 million for the yearended December 31, 2006.  Thedecrease in cash provided by operating activities was primarily due to premiumspaid for derivatives of approximately $279.3 million.  The premiums paid were for derivativecontracts that hedge 284,985 MMcfe of future production for $2.68 billion ofoil and gas property acquisitions (see Note 2) for up to five years.  These hedges are expected to provide orstabilize the Company’s future cash flow and were funded through the Company’s creditfacility.  See Note 9 for additional details about commodity derivatives.

 

As part of its overall strategy, the Company regularly enters intolong-term commodity derivative contracts in the form of swaps and puts to hedgeits future production.  The Company’sintent is to hold these contracts to maturity. As is common in the marketplace, the Company at times is required to paycash premiums to enter into such contracts. The majority of the Company’s premiums to date have been paid on putcontracts, since these contracts contain optionality related to changes infuture prices that allow the Company to realize increased cash flows shouldfuture prices increase.  The derivativecontracts “hedge” the Company’s future production as the contracts provide theCompany with a minimum realizable cash flow related to its hedged futureproduction.  The Company typically entersinto additional put and swap contracts in conjunction with the acquisition ofoil and gas properties, since its future production 

 

40

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**Item7.    Management’s Discussion and Analysisof Financial Condition and Results of Operation****-****Continued**

 

increases at that time.  In orderto hedge the significant increase in production anticipated as a result of its August 2007and January 2008 acquisitions (see Note 2), the Company purchasedadditional commodity derivative contracts in the third and fourth quarters of2007 and paid premiums of approximately $226.3 million for these contracts.  The Company expects to purchase additionalderivative contracts in the future, as it acquires additional oil and gasproperties.  The amount of derivativecontracts the Company enters into in the future will be directly related toexpected production from future acquisitions, and cannot be predicted at thistime.  See Item 7A. “Quantitative and QualitativeDisclosures About Market Risk,” for details about derivatives the Companyentered into subsequent to December 31, 2007.

 

***Statements of Cash Flows — Investing Activities***

 

Cash used in investing activities wasapproximately $2.89 billion for the year ended December 31, 2007, comparedto $551.6 million for the year ended December 31, 2006.  The increase in cash used in investingactivities was primarily due to an increase in acquisition activity during theyear ended December 31, 2007, compared to the same period of the prioryear.

 

The total cash used in investing activities for the year ended December 31,2007 includes $2.03 billion for the August 2007 acquisition of propertiesin the Mid-Continent, $555.5 million for the February, June and October 2007acquisitions in the Mid-Continent and $38.6 million for the acquisitions of certain gasproperties in West Virginia (seeNote 2).  Other acquisitions, includingacquisitions of additional working interests in current wells, wereapproximately $41.5 million and property, plant and equipment purchases were$17.9 million.  The total for the yearended December 31, 2007 also includes $185.5 million for the drilling anddevelopment of oil and gas properties and pipeline costs.  For 2008, the Company estimates itstotal drilling and development capital expenditures will be between $250.0million and $300.0 million.  Thisestimate is under continuous review and is subject to on-going adjustment.

 

***Statements of Cash Flows — FinancingActivities***

 

Cash provided by financing activities wasapproximately $2.93 billion for the year ended December 31, 2007, comparedto $554.0 million for the year ended December 31, 2006.

 

The Company recorded gross proceeds of $2.12 billion from three privateplacements of its units during the year ended December 31, 2007.  The net proceeds of approximately $2.09billion were used to finance theMid-Continent acquisitions, the acquisitions of certain gas propertiesin West Virginia, and to repay indebtedness under the Company’s creditfacility.  During the year ended December 31, 2007, totalproceeds from the issuance of debt were $1.3 billion and total repayments ofdebt were $283.1 million.

 

***Distributions***

 

Underthe limited liability company agreement, Company unitholders are entitled toreceive a quarterly distribution of available cash to the extent there issufficient cash from operations after establishment of cash reserves and paymentof fees and expenses.  The followingprovides a summary of distributions paid by the Company during the year ended December 31,2007:

 
| **Date Paid**      | ** ** | **Period Covered by Distribution**      | ** ** | **Distribution  Per Unit** | ** ** | **Total  Distribution** | ** ** |
|--------------------|------------|-----------------------------------------|------------|----------------------------|------------|-------------------------|------------|
|               |       |                                    |       |                       |       | **(in  thousands)**     |       |
|               |       |                                    |       |                       |       |                    |       |
| November 2007 |       | July 1 - September 30, 2007   |       | $                          | 0.57       |                    | $          | 64,798 |   |
| August 2007   |       | April 1 - June 30, 2007       |       | $                          | 0.57       |                    | 37,419     |   |
| May 2007      |       | January 1 - March 31, 2007    |       | $                          | 0.52       |                    | 30,001     |   |
| February 2007 |       | October 1 - December 31, 2006 |       | $                          | 0.52       |                    | 22,745     |   |
|               |       |                                    |       |                       |       | $                       | 154,963    |   |

 

41

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**Item7.    Management’s Discussion and Analysisof Financial Condition and Results of Operation****-****Continued**

 

In January 2008, the Company’s Board of Directors declared a cashdistribution of $0.63 per unit with respect to the fourth quarter of 2007.  The distribution totaled approximately $72.2 million and waspaid on February 14, 2008 to unitholders of record as of the close ofbusiness on February 8, 2008.  Thisdistribution represents a 10.5% increase in the Company’s annualized cashdistribution rate, to $2.52 per unit, from $2.28 per unit for the third quarterof 2007.

 

***Private Placements***

 

See “Executive Summary” above and Note 4 for details about the Company’sprivate placements.

 

***CreditFacility***

 

At December 31, 2007, the Company had a$1.8 billion ThirdAmended and Restated Credit Agreement (“CreditFacility”) and a maturity of August 2010. In connection with its Credit Facility, the Company paidapproximately $9.3 million in financing fees, which were deferred and areamortized over the life of the Credit Facility. In addition, during the year ended December 31, 2007, the Companywrote off deferred financing fees related to its prior credit facility ofapproximately $2.8 million.  On January 31,2008, the Credit Facility was amended to increase the amount available forborrowing to $1.9 billion, all of which is conforming, effective until April 1,2008, at which point the borrowing base will be redetermined in accordance withthe terms of the Credit Facility.  At January 31,2008, the Company had $314.5 million available for borrowing under its CreditFacility.

 

The borrowing baseunder the Credit Facility will be redetermined semi-annually by the lenders intheir sole discretion, based on, among other things, reserve reports asprepared by reserve engineers taking into account the oil and gas prices atsuch time.  The Company’s obligationsunder the Credit Facility are secured by mortgages on its oil and gasproperties as well as a pledge of all ownership interests in its operatingsubsidiaries.  The Company is required tomaintain the mortgages on properties representing at least 80% of its oil andgas properties.  Additionally, theobligations under the Credit Facility are guaranteed by all of the Company’soperating subsidiaries and may be guaranteed by any future subsidiaries.

 

At the Company’selection, interest on borrowings under the Credit Facility is determined byreference to either LIBOR plus an applicable margin between 1.00% and 2.25% perannum or the alternate base rate (“ABR”) plus an applicable margin between 0%and 0.75% per annum.  Interest isgenerally payable quarterly for ABR loans and at the applicable maturity datefor LIBOR loans.

 

The CreditFacility contains various covenants that limit the Company’s ability to incurindebtedness, enter into interest rate swaps, grant certain liens, make certainloans, acquisitions, capital expenditures and investments, make distributionsother than from available cash, merge or consolidate, or engage in certainasset dispositions, including a sale of all or substantially all of itsassets.  The Credit Facility alsocontains covenants that require the Company to maintain Adjusted EBITDA tointerest expense and current liquidity financial ratios.  The Company is in compliance with allfinancial and other covenants of its Credit Facility.

 

As noted above,the Company depends on its Credit Facility for future capital needs.  In addition, the Company has drawn on theCredit Facility to fund or partially fund quarterly cash distribution payments,since it uses operating cash flows for investing activities and borrows as cashis needed.  Absent such borrowing, theCompany would have at times experienced a shortfall in cash available to paythe declared quarterly cash distribution amount.  If there is a default under the CreditFacility, the Company would be unable to make borrowings to fund distributions.

 

***Term Loan***

 

On January 31,2008, in order to fund a portion of the January 2008 acquisition of oiland gas properties in the Mid-Continent (see “Recent Developments” above), theCompany entered into a $400.0 million Second Lien Term Loan Agreement with amaturity of July 31, 2009 (“Term Loan”). In connection with the Term Loan, the Company paid financing fees ofapproximately $6.0 million, which were deferred and amortized over the life ofthe Term Loan.  The Company’s obligationsunder the Term Loan are secured by a second priority lien on all oil and gasproperties as well as a second priority pledge on all ownership interests inits operating subsidiaries.  The Company’sobligations under the Term Loan are guaranteed by all the Company’s operatingsubsidiaries and may be guaranteed 

 

42

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**Item7.    Management’s Discussion and Analysisof Financial Condition and Results of Operation****-****Continued**

 

by any futuresubsidiaries.  Covenants under the TermLoan are substantially similar to those under the Credit Facility.  Interest is determined by reference to LIBORplus an applicable margin of 5.0% for the first twelve months and 7.5% for theremaining period until maturity or a domestic bank rate plus an applicablemargin of 3.5% for the first twelve months and 6.0% for the remaining perioduntil maturity.

 

***Off-BalanceSheet Arrangements***

 

At December 31, 2007, the Company did not have any off-balancesheet arrangements that have, or are reasonably likely to have, a materialeffect on its financial position or results of operations.

 

***Contingencies***

 

During the years ended December 31, 2007, 2006, and 2005 nosignificant payments were made to settle any of the Company’s legalproceedings.  The Company regularlyanalyzes current information and accrues for probable liabilities on thedisposition of certain matters, as necessary. Liabilities for loss contingencies arising from claims, assessments,litigation or other sources are recorded when it is probable that a liabilityhas been incurred and the amount can be reasonably estimated.

 

43

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**Item7.    Management’s Discussion and Analysisof Financial Condition and Results of Operation****-****Continued**

 

***Commitmentsand Contractual Obligations***

 

The following summarizes, as of December 31, 2007, certainlong-term contractual obligations that are reflected in the consolidatedbalance sheet and/or disclosed in the accompanying notes thereto:

 
| ** **                                     | ** ** | **Payments Due** | ** ** |
|------------------------------------------------|------------|------------------|------------|
| **Contractual Obligations**                    | ** ** | **Total**        | ** ** | **2008** | ** ** | **2009 — 2010** | ** ** | **2011 — 2012** | ** ** | **2013 and   Beyond** | ** ** |
| ** **                                     |       |             |       |   |   | **(in  thousands)** |   |   |   |   |   |
| **Long-term debt obligations:**                | ** ** | ** **       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Long-term notes  payable                       |       | $                | 1,521      |   | $ | 691 |   | $ | 501 |   | $ | 47 |   | $ | 282 |   |
| Credit Facility                                |       | 1,443,000        |       | — |   | 1,443,000 |   | — |   | — |   |
| Interest on  Credit Facility computed at 7.02% |       | 261,688          |       | 101,299 |   | 160,389 |   | — |   | — |   |
| **Operating lease obligations:**               | ** ** | ** **       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Office, property  and equipment leases         |       | 15,947           |       | 2,752 |   | 5,696 |   | 4,933 |   | 2,566 |   |
| **Other noncurrent liabilities:**              | ** ** | ** **       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Asset retirement  obligations                  |       | 29,073           |       | — |   | — |   | 204 |   | 28,869 |   |
| **Other:**                                     | ** ** | ** **       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Derivative  instruments                        |       | 69,961           |       | 6,148 |   | 48,582 |   | 5,568 |   | 9,663 |   |
| Drilling and  other contracts                  |       | 24,136           |       | 8,206 |   | 15,827 |   | 103 |   | — |   |
| Total                                          |       | $                | 1,845,326  |   | $ | 119,096 |   | $ | 1,673,995 |   | $ | 10,855 |   | $ | 41,380 |   |

 

***Capital Structure***

 

The Company’s capitalization is presentedbelow:

 
| ** **                       | ** ** | **December 31,** | ** ** |
|----------------------------------|------------|-----------------------|------------|
| ** **                       | ** ** | **2007**              | ** ** | **2006** | ** ** |
|                             |       | **(in  thousands)**   |       |
|                             |       |                  |       |   |   |
| Cash and cash  equivalents       |       | $                     | 1,441      |   | $ | 6,595 |   |
| Credit facility                  |       | $                     | 1,443,000  |   | $ | 425,750 |   |
| Other noncurrent  debt           |       | 830                   |       | 2,487 |   |
|                             |       | 1,443,830             |       | 428,237 |   |
| Total  unitholders’ capital |       | 2,026,641             |       | 450,954 |   |
| Total  capitalization            |       | $                     | 3,470,471  |   | $ | 879,191 |   |

 

44

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**Item 7.    Management’s Discussion and Analysis of Financial Condition andResults of Operation****-****Continued**

 

**Non-GAAP Financial Measure**

 

**Adjusted EBITDA**

 

The Company defines AdjustedEBITDA as net income (loss) plus:

 

·                  Net operating cash flow from acquisitions, effective date throughclosing date;

 

·                  Interest expense, net of amounts capitalized;

 

·                  Depreciation, depletion and amortization;

 

·                  Write-off of deferred financing fees andother;

 

·                  (Gain) loss on sale of assets;

 

·                  Accretion of asset retirement obligation;

 

·                  Unrealized (gain) loss on derivatives;

 

·                  Unit-based compensation and unit warrantexpense;

 

·                  Data license expenses;

 

·                  IPO cash bonuses; and

 

·                  Income tax (benefit) provision.

 

Adjusted EBITDA is a significantperformance metric used by Company management to indicate (prior to theestablishment of any reserves by its Board of Directors) the cash distributionsthe Company expects to pay unitholders. Specifically, this financial measure indicates to investors whether ornot the Company is generating cash flow at a level that can sustain or supportan increase in its quarterly distribution rates.  Adjusted EBITDA is also a quantitative metricused throughout the investment community with respect to publicly-tradedpartnerships and limited liability companies.

 

The following presents areconciliation of consolidated net income (loss) to Adjusted EBITDA:

 
| ** **                                                                          | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                          | ** ** | **2007**                         | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                                          | ** ** | **(in thousands)**               | ** ** |
|                                                                                |       |                             |       |   |   |   |   |
| Net income (loss)                                                                   |       | $                                | (364,349   | ) | $ | 79,185 |   | $ | (56,351 | ) |
| Plus:                                                                               |       |                             |       |   |   |   |   |
| Net operating  cash flow from acquisitions, effective date through closing date (1) |       | 67,417                           |       | 712 |   | — |   |
| Interest  expense, net of amounts capitalized                                       |       | 62,130                           |       | 25,494 |   | 7,040 |   |
| Depreciation,  depletion and amortization                                           |       | 97,964                           |       | 24,173 |   | 7,294 |   |
| Write-off of  deferred financing fees and other                                     |       | 3,460                            |       | 3,342 |   | 381 |   |
| (Gain) loss on  sale of assets                                                      |       | 813                              |       | 72 |   | 39 |   |
| Accretion of  asset retirement obligation                                           |       | 1,014                            |       | 314 |   | 172 |   |
| Unrealized  (gain) loss on derivatives                                              |       | 418,281                          |       | (77,776 | ) | 24,776 |   |
| Realized loss on  canceled gas derivatives (2)                                      |       | —                           |       | — |   | 38,281 |   |
| Unit-based  compensation expense and unit warrant expense                           |       | 13,921                           |       | 21,643 |   | — |   |
| Data license  expenses                                                              |       | 3,231                            |       | — |   | — |   |
| IPO cash bonuses                                                                    |       | —                           |       | 2,039 |   | — |   |
| Income tax  (benefit) provision  (3)                                                |       | 3,573                            |       | (3,402 | ) | 74 |   |
| Adjusted EBITDA                                                                     |       | $                                | 307,455    |   | $ | 75,796 |   | $ | 21,706 |   |

----

(1)              Includes net operating cash flow fromacquisitions through the date of this report, including the Mid-Continent IVacquisition (see Note 2).

 

(2)              During the year ended December 31,2005, the Company canceled (before their original settlement date) a portion ofout-of-the-money gas swaps and realized a loss of $38.3 million.  The Company subsequently hedged similarvolumes at higher prices.

 

(3)              The Company’s taxable subsidiariesgenerated net operating losses during the year ended December 31,2006.  Management subsequently recoveredexpenses through an intercompany charge for services from Linn Operating, Inc.to Linn Energy, which resulted in a corresponding tax expense during the year endedDecember 31, 2007.

 

45

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**Item 7.    Management’s Discussion and Analysis of Financial Condition andResults of Operation****-****Continued**

 

As noted above, Adjusted EBITDA is non-GAAPperformance measure used by Company management to indicate the cashdistributions the Company expects to pay unitholders.  On the consolidated statements of cash flows,net cash used by operating activities for the year ended December 31,2007, was approximately $44.8 million and includes approximately $279.3 millioninvested in derivatives.  Net cash usedby operating activities for the year ended December 31, 2006, wasapproximately $6.8 million and includes $49.8 million invested inderivatives.  Net cash used by operatingactivities for the year ended December 31, 2005 was approximately $29.5million and includes a $38.3 million realized loss on cancelledout-of-the-money gas swaps.

 

**Critical Accounting Policies andEstimates**

 

The discussion andanalysis of the Company’s financial condition and results of operations isbased upon the consolidated financial statements, which have been prepared inaccordance with U.S. generally accepted accounting principles (“GAAP”).  The preparation of these financial statementsrequires the Company to make estimates and assumptions that affect the reportedamounts of assets, liabilities, revenues and expenses, and related disclosureof contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to suchan extent that there is reasonable likelihood that materially different amountscould have been reported under different conditions, or if differentassumptions had been used.  The Companyevaluates its estimates and assumptions on a regular basis.  The Company bases estimates on historicalexperience and various other assumptions that are believed to be reasonableunder the circumstances, the results of which form the basis for makingjudgments about the carrying values of assets and liabilities that are not readilyapparent from other sources.  Actualresults may differ from these estimates and assumptions used in the preparationof financial statements.  Below, theCompany has provided expanded discussion of its more significant accountingpolicies, estimates and judgments.  Theseaccounting policies reflect more significant estimates and assumptions used inthe preparation of financial statements. See Note 1 for a discussion of additional accounting policies andestimates made by Company management.

 

***Oil and Gas Reserves***

 

The Company’sestimates of proved reserves are based on the quantities of oil, gas and NGLthat engineering and geological analyses demonstrate, with reasonablecertainty, to be recoverable from established reservoirs in the future undercurrent operating and economic parameters. The independent engineering firm DeGolyer and MacNaughton prepared areserve and economic evaluation of all of the Company properties on awell-by-well basis as of December 31, 2007.

 

Reserves and theirrelation to estimated future net cash flows impact the Company’s depletion andimpairment calculations.  As a result,adjustments to depletion and impairment are made concurrently with changes toreserve estimates.  The Company preparesits reserve estimates, and the projected cash flows derived from these reserveestimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the sameguidelines when preparing their reserve reports.  The accuracy of the reserve estimates is a functionof many factors including the following: the quality and quantity of availabledata, the interpretation of that data, the accuracy of various mandatedeconomic assumptions and the judgments of the individuals preparing theestimates.

 

The Company’s provedreserve estimates are a function of many assumptions, all of which coulddeviate significantly from actual results. As such, reserve estimates may materially vary from the ultimatequantities of oil, gas and NGL eventually recovered.

 

***Oil and Gas Properties/Propertyand Equipment***

 

*ProvedOil and Gas Properties*

The Companyaccounts for oil and gas properties under the successful efforts method.  Under this method, all acquisition anddevelopment costs of proved properties are capitalized and amortized on aunit-of-production basis over the remaining life of the proved reserves andproved developed reserves, respectively.

 

The Companyevaluates the impairment of its proved oil and gas properties on afield-by-field basis whenever events or changes in circumstances indicate anasset’s carrying amount may not be recoverable. The carrying amount of proved oil and gas properties are reduced to fairvalue when the expected undiscounted future cash flows 

 

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**Item7.    Management’s Discussion and Analysisof Financial Condition and Results of Operation****-****Continued**

 

are less than the asset’s net book value.  Cash flows are determined based upon reservesusing prices, costs and discount factors consistent with those used forinternal decision making.  The underlyingcommodity prices embedded in the Company’s estimated cash flows are the productof a process that begins with the Henry Hub forward curve pricing, adjusted forestimated location and quality differentials, as well as other factors thatmanagement believes will impact realizable prices.  Although prices used are likely toapproximate market, they do not necessarily represent current market prices.  Costs of retired, sold or abandonedproperties that constitute a part of an amortization base are charged orcredited, net of proceeds, to accumulated depreciation, depletion andamortization unless doing so significantly affects the unit-of-productionamortization rate, in which case a gain or loss is recognized currently.  Gains or losses from the disposal of otherproperties are recognized currently. Expenditures for maintenance and repairs necessary to maintainproperties in operating condition are expensed as incurred.  Major replacements are capitalized.  Estimated dismantlement and abandonment costsfor oil and gas properties are capitalized, net of salvage, at their estimatednet present value and amortized on a unit-of-production basis over theremaining life of the related proved developed reserves.

 

*Unproved**Oil and Gas Properties*

Unproved properties consist of costs incurred to acquire unprovedleasehold as well as costs incurred to acquire unproved resources.  Unproved leasehold costs are capitalized andamortized on a composite basis if individually insignificant, based on pastsuccess, experience and average lease-term lives.  Unamortized leasehold costs related tosuccessful exploratory drilling are reclassified to proved properties anddepleted on a unit-of-production basis. The carrying value of the Company’s unproved resources, which wereacquired in connection with business acquisitions, was determined using the market-based weighted average cost ofcapital rate, subjected to additional project-specific risking factors.  Because these reserves do notmeet the definition of proved reserves, the related costs are not classified asproved properties.  As the unprovedresources are developed and proven, the associated costs are reclassified toproved properties and depleted on a unit-of-production basis.  The Company assesses unproved resources forimpairment annually by comparing book value to fair value, which is determinedusing discounted estimates of future cash flows.

 

*Other Property and Equipment*

Other property and equipment includes gas gathering systems, pipelines,buildings, data processing and telecommunications equipment, office furnitureand equipment, and other fixed assets. These items are recorded at cost and are depreciated using thestraight-line method based on expected lives ranging from 3 to 39 years for theindividual asset or group of assets.

 

***Goodwill***

 

Goodwill represents the excess of the cost of an acquired business overthe net amounts assigned to assets acquired and liabilities assumed.  Goodwill is not amortized to earnings but istested annually during the fourth quarter or whenever events or changes incircumstances indicate that the carrying value may not be recoverable.  At December 31, 2007, goodwill on theCompany’s consolidated balance sheet of $64.4 million represents goodwillrecorded in the fourth quarter of 2007 in connection with the Company’sMid-Continent III acquisition (see Note 2).  Future changes in goodwill may result from,among other things, finalization of preliminary purchase price allocations,impairments, or future acquisitions.

 

***Revenue Recognition***

 

Sales of oil, gas and NGL are recognized when oil, gas or NGL has beendelivered to a custody transfer point, persuasive evidence of a salesarrangement exists, the rights and responsibility of ownership pass to thepurchaser upon delivery, collection of revenue from the sale is reasonablyassured, and the sales price is fixed or determinable.  Virtually all of the Company’s contractpricing provisions are tied to a market index, with certain adjustments basedon, among other factors, whether a well delivers to a gathering or transmissionline, quality of oil, gas and NGL, and prevailing supply and demand conditions,so that prices fluctuate to remain competitive with other available suppliers.

 

The Company haselected the entitlements method to account for gas imbalances.  Gas imbalances occur when the Company sellsmore or less than its entitled ownership percentage of total gas production.  Under the entitlements method, any amountreceived in excess of the Company’s share is treated as a liability.  If the Company receives 

 

47

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**Item7.    Management’s Discussion and Analysisof Financial Condition and Results of Operation****-****Continued**

 

less than itsentitled share, the underproduction is recorded as a receivable.  At December 31, 2007, the Company had agas imbalance receivable of approximately $6.6 million, which is included inaccounts receivable — trade, net, on the consolidated balance sheet.  The Company did not have any significant gasimbalance positions at December 31, 2006.

 

The Companyengages in the purchase, gathering and transportation of third-party naturalgas and subsequently markets such gas to independent purchasers under separatearrangements.  As such, the Companyseparately reports third-party marketing sales and natural gas marketingexpenses.  Marketing margins related tothe Company’s production are included in oil, gas and NGL sales.

 

The Companygenerates electricity with excess gas, which it uses to serve certain of itsoperating facilities in Brea, California. Any excess electricity is sold to the California wholesale powermarket.  This revenue is included in otherrevenues on the consolidated statements of operations.

 

***Asset Retirement Obligations***

 

The Company hasthe obligation to plug and abandon oil and gas wells and related equipment atthe end of production operations. Estimated asset retirement costs are recognized when the obligation isincurred, and are amortized over proved developed reserves using the units ofproduction method.  Asset retirementcosts are estimated by the Company’s engineers using existing regulatoryrequirements and anticipated future inflation rates.  Revisions in estimated liabilities can resultfrom revisions of estimated inflation rates, escalating retirement costs andchanges in the estimated timing of settling asset retirement obligations (seeNote 11).

 

***Derivative Instruments***

 

The Company usesderivative financial instruments to achieve a more predictable cash flow fromits oil, gas and NGL production by reducing its exposure to pricefluctuations.  As of December 31,2007, these transactions were in the form of swaps and puts.  A put option requires the Company to pay thecounterparty a premium equal to the fair value of the option at the purchasedate and receive from the counterparty the excess, if any, of the fixed floorover the floating market price. Additionally, the Company uses derivative financial instruments in theform of interest rate swaps to mitigate its interest rate exposure.

 

The Companyaccounts for these activities pursuant to SFAS 133.  This statement establishes accounting andreporting standards requiring that derivative instruments (including certainderivative instruments embedded in other contracts) be recorded at fair valueand included in the balance sheet as assets or liabilities.  The Company accounts for its derivatives atfair value as an asset or liability and the change in the fair value of thederivatives is included in earnings since none of the Company’s commodity orinterest rate derivatives are designated as hedges under SFAS 133.  See Item 7A. “Quantitative andQualitative Disclosures About Market Risk” for discussion regarding the Company’ssensitivity analysis for the Company’s financial instruments and interest rateswaps.

 

***Purchase Accounting***

 

The establishmentof the asset base through the date of this report has included 22 acquisitionsof working interests in oil and gas properties. These acquisitions have been accounted for using the purchase method ofaccounting as prescribed in SFAS No. 141, *“BusinessCombinations.”*  SeeNote 2 for additional details about acquisitions.

 

In connection witha business combination, the acquiring company must allocate the cost of theacquisition to assets acquired and liabilities assumed based on fair values asof the acquisition date.  The purchaseprice allocations are based on independent appraisals, discounted cash flows,quoted market prices and estimates by management.  In addition, when appropriate, the Companyreviews comparable purchases and sales of oil and gas properties within thesame regions, and uses that data as a proxy for fair market value; i.e., theamount a willing buyer and seller would enter into in exchange for suchproperties.  Any excess of purchase priceover amounts assigned to assets and liabilities is recorded as goodwill.  The amount of goodwill recorded in anyparticular business combination can vary significantly depending upon the valueattributed to assets acquired and liabilities assumed.

 

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**Item7.    Management’s Discussion and Analysisof Financial Condition and Results of Operation****-****Continued**

 

The Company madevarious assumptions in estimating the fair values of assets acquired andliabilities assumed.  The mostsignificant assumptions related to the estimated fair values assigned to provedand unproved oil and gas properties.  Toestimate the fair values of these properties, the Company prepared estimates ofoil and gas reserves.  The Companyestimated future prices to apply to the estimated reserve quantities acquired,and estimated future operating and development costs, to arrive at estimates offuture net revenues.  For estimatedproved reserves, the future net revenues were discounted using a market-basedweighted average cost of capital rate determined appropriate at the time of theacquisition.  The market-based weightedaverage cost of capital rate was subjected to additional project-specificrisking factors.  To compensate for theinherent risk of estimating and valuing unproved properties, the discountedfuture net revenues of probable and possible reserves were reduced byadditional risk-weighting factors.

 

Deferred taxesmust be recorded for any differences between the assigned values and tax basesof assets and liabilities.  Estimateddeferred taxes are based on available information concerning the tax basis ofassets acquired and liabilities assumed and loss carryforwards at the acquisitiondate, although such estimates may change in the future as additionalinformation becomes known.

 

While theestimates of fair value for the assets acquired and liabilities assumed have noeffect on cash flows, they can have an effect on the future results ofoperations.  Generally, higher fairvalues assigned to oil and gas properties result in higher future depreciation,depletion and amortization expense, which results in a decrease in future netearnings.  Also, a higher fair valueassigned to oil and gas properties, based on higher future estimates of oil andgas prices, could increase the likelihood of an impairment in the event oflower commodity prices or higher operating costs than those originally used todetermine fair value.  An impairment wouldhave no effect on cash flows but would result in a decrease in net income forthe period in which the impairment is recorded.

 

***Unit-Based Compensation***

 

The Companyaccounts for unit-based compensation pursuant to SFAS No. 123 (revised 2004), *“Share-Based Payment”*(“SFAS123R”).  SFAS 123R requires an entity to recognizethe grant-date fair-value of stock options and other equity-based compensationissued to employees in the income statement and eliminates the alternative touse the intrinsic value method of accounting that was provided under theoriginal provisions of SFAS 123, which resulted in no compensation expenserecorded in the financial statements related to the issuance of equity awardsto employees.  It establishes fair valueas the measurement objective in accounting for share-based payment arrangementsand requires companies to apply a fair-value-based measurement method inaccounting for share-based payment transactions with employees.  The Company also follows the guidance inStaff Accounting Bulletin (“SAB”) No. 107,*“Share-Based Payment,”* which contains the express views of the SECstaff regarding the interaction between SFAS 123R and certain SEC rules andregulations and provides the staff’s views regarding the valuation ofshare-based payment arrangements for public companies.  The Company recorded no unit-basedcompensation expense for the year ended December 31, 2005, as there wereno unit-based payments made during that year. See Note 6 for additional details about the Company’s accountingfor unit-based compensation.

 

**New Accounting Pronouncements**

 

There have been no new accounting standards that materially affected theCompany this period; however, see Note 15 for details regardingFIN 48.

 

See Note 1for details regarding the Company’s change in accounting policy related to thebalance sheet presentation of derivative instruments in accordance with theprovisions of FASB Interpretation No. 39, *“Offsettingof Amounts Related to Certain Contracts.*”

 

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**Item 7A.****Quantitative and Qualitative Disclosures About Market Risk**

 

The primary objective of the following information is to provideforward-looking quantitative and qualitative information about potentialexposure to market risks.  The term “marketrisk” refers to the risk of loss arising from adverse changes in oil, gas andNGL prices and interest rates.  Thedisclosures are not meant to be precise indicators of expected future losses,but rather indicators of reasonably possible losses.  This forward-looking information providesindicators of how the Company views and manages its ongoing market riskexposures.  All of the Company’s marketrisk sensitive instruments were entered into for purposes other thanspeculative trading.

 

A reference to a “Note”herein refers to the accompanying Notes to Consolidated Financial Statementscontained in Item 8. “Financial Statements and Supplementary Data.”

 

**Commodity Price Risk**

 

The Company’s major market risk exposure is in the pricing applicable tooil, gas and NGL production.  Realizedpricing is primarily driven by the spot market prices applicable to productionand the prevailing price for oil, gas and NGL. Pricing for oil, gas and NGL production has been historically volatileand unpredictable, and this volatility is expected to continue in thefuture.  The prices the Company receivesfor production depend on many factors outside of its control.

 

The Company enters into hedging arrangements with respect to a portionof its projected production through various transactions that hedge the futureprices received.  See Note 9 foradditional details.  These transactionsmay include price swaps whereby the Company will receive a fixed price forproduction and pay a variable market price to the contract counterparty.  At the settlement date, the Company receivesthe excess, if any, of the fixed NYMEX or PEPL price floor over the floatingrate.  Additionally, the Company has putoptions for which it pays the counterparty the fair value at the purchasedate.  These hedging activities areintended to support commodity prices at targeted levels and to manage exposureto oil, gas and NGL price fluctuations.

 

At December 31, 2007, the fair value of hedges that settle duringthe next twelve months was an asset of approximately $22.3 million and aliability of approximately $3.9 million for a net asset of approximately $18.4million, which the Company is owed by counterparties.  A 10% increase in the index oil and gasprices above the December 31, 2007 prices for the next twelve months wouldresult in a reduction in the value of the hedges of approximately $53.9million; conversely, a 10% decrease in the index oil and gas prices wouldresult in an increase of approximately $56.5 million.

 

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**Item7A.****Quantitative and Qualitative Disclosures About Market Risk********-****Continued**

 

The following table summarizes, as of February 22, 2008, and forthe periods indicated, derivatives in place through December 31, 2013.

 
| ** **                            | ** ** | **February 22 -   December 31,   2008** | ** ** | **Year  2009** | ** ** | **Year  2010** | ** ** | **Year  2011** | ** ** | **Year  2012** | ** ** | **Year  2013** | ** ** |
|---------------------------------------|------------|---------------------------------------------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|
| **Gas Positions:**                    |       |                                              |       |           |       |           |       |           |       |           |       |           |       |
| Fixed Price Swaps:                    |       |                                              |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMMBtu)               |       | 41,134                                            |       | 49,271         |       | 42,086         |       | 38,741         |       | 34,066         |       | —         |       |
| Average Price  ($/MMBtu)              |       | $                                                 | 8.48       |           | $          | 8.32           |       | $              | 8.14       |           | $          | 8.08           |       | $ | 8.45 |   | $ | — |   |
| Puts:                                 |       |                                              |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMMBtu)               |       | 5,883                                             |       | 6,960          |       | 6,960          |       | 6,960          |       | —         |       | —         |       |
| Average Price ($/MMBtu)               |       | $                                                 | 8.07       |           | $          | 7.50           |       | $              | 7.50       |           | $          | 7.50           |       | $ | — |   | $ | — |   |
| PEPL Puts: (1)                        |       |                                              |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMMBtu)               |       | 3,212                                             |       | 5,334          |       | 10,634         |       | 13,259         |       | 5,934          |       | —         |       |
| Average Price  ($/MMBtu)              |       | $                                                 | 7.85       |           | $          | 7.85           |       | $              | 7.85       |           | $          | 7.85           |       | $ | 7.85 |   | $ | — |   |
| Total:                                |       |                                              |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMMBtu)               |       | 50,229                                            |       | 61,565         |       | 59,680         |       | 58,960         |       | 40,000         |       | —         |       |
| Average Price  ($/MMBtu)              |       | $                                                 | 8.39       |           | $          | 8.19           |       | $              | 8.02       |           | $          | 7.96           |       | $ | 8.36 |   | $ | — |   |
|                                  |       |                                              |       |           |       |           |       |           |       |           |       |           |       |
| **Oil Positions:**                    |       |                                              |       |           |       |           |       |           |       |           |       |           |       |
| Fixed Price Swaps:                    |       |                                              |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MBbls)                |       | 2,364                                             |       | 2,437          |       | 2,150          |       | 2,073          |       | 2,025          |       | 900            |       |
| Average Price  ($/Bbl)                |       | $                                                 | 82.42      |           | $          | 78.07          |       | $              | 78.28      |           | $          | 79.65          |       | $ | 77.65 |   | $ | 72.22 |   |
| Puts: (2)                             |       |                                              |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MBbls)                |       | 1,557                                             |       | 1,843          |       | 2,250          |       | 2,352          |       | 500            |       | —         |       |
| Average Price ($/Bbl)                 |       | $                                                 | 73.34      |           | $          | 72.13          |       | $              | 70.56      |           | $          | 69.11          |       | $ | 77.73 |   | $ | — |   |
| Total:                                |       |                                              |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MBbls)                |       | 3,921                                             |       | 4,280          |       | 4,400          |       | 4,425          |       | 2,525          |       | 900            |       |
| Average Price  ($/Bbl)                |       | $                                                 | 78.81      |           | $          | 75.51          |       | $              | 74.33      |           | $          | 74.05          |       | $ | 77.66 |   | $ | 72.22 |   |
|                                  |       |                                              |       |           |       |           |       |           |       |           |       |           |       |
| **Gas Basis Differential Positions:** |       |                                              |       |           |       |           |       |           |       |           |       |           |       |
| PEPL Basis Swaps: (3)                 |       |                                              |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMMBtu)               |       | 30,122                                            |       | 34,666         |       | 29,366         |       | 26,741         |       | 34,066         |       | —         |       |
| Hedged  Differential ($/MMBtu)        |       | $                                                 | (0.95      | )              | $          | (0.95          | )          | $              | (0.95      | )              | $          | (0.95          | )          | $ | (0.95 | ) | $ | — |   |

----

(1)              Settle on the PEPL spot price of gas to hedge basisdifferential associated with gas production in the Mid-Continent region.

 

(2)              The Company utilizes oil puts to hedge revenuesassociated with its NGL production.

 

(3)              Represents a swap of the basis between NYMEX and thePEPL spot price of gas of $(0.95) per MMBtu for the volumes hedged.

 

**Interest Rate Risk**

 

At December 31, 2007, the Company had long-term debt outstanding of$1.44 billion under its Credit Facility, which incurred interest at floatingrates in accordance the Credit Facility agreement.  See Note 7 for additional details aboutthe Credit Facility.  As of December 31,2007, the interest rate based on LIBOR was approximately 7.02%.  A 1% increase in LIBOR would result in anestimated $12.5 million increase in annual interest expense associated with theCredit Facility.

 

The Company has entered into interest rate swap agreements based onLIBOR to minimize the effect of fluctuations in interest rates.  If LIBOR is lower than the fixed rate in thecontract, the Company is required to pay the counterparties the difference, andconversely, the counterparties are required to pay the Company if LIBOR ishigher than the fixed rate in the contract. See Note 8 for additional details.

 

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**Item 8.    Financial Statements and Supplementary Data**

 

**INDEX TO FINANCIAL STATEMENTS andSUPPLEMENTARY DATA**

 
| ** **                                                                                                                  | ** ** | **Page** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------|------------|----------|------------|
|                                                                                                                        |       |     |       |
| Management’s  Report on Internal Control Over Financial Reporting                                                      |       | 53       |       |
|                                                                                                                        |       |     |       |
| Report  of Independent Registered Public Accounting Firm (Financial Statements)                                             |       | 54       |       |
|                                                                                                                        |       |     |       |
| Report  of Independent Registered Public Accounting Firm (Internal Control Over  Financial Reporting)                       |       | 55       |       |
|                                                                                                                        |       |     |       |
| Consolidated Balance  Sheets, as of December 31, 2007 and 2006                                                         |       | 56       |       |
|                                                                                                                        |       |     |       |
| Consolidated  Statements of Operations, for the years ended December 31, 2007, 2006  and 2005                          |       | 57       |       |
|                                                                                                                        |       |     |       |
| Consolidated  Statements of Unitholders’ Capital (Deficit), for the years ended  December 31, 2007, 2006 and 2005 |       | 58       |       |
|                                                                                                                        |       |     |       |
| Consolidated  Statements of Cash Flows, for the years ended December 31, 2007, 2006  and 2005                          |       | 59       |       |
|                                                                                                                        |       |     |       |
| Notes to  Consolidated Financial Statements                                                                                 |       | 60       |       |
|                                                                                                                        |       |     |       |
| Supplemental  Oil and Gas Data (Unaudited)                                                                                  |       | 85       |       |
|                                                                                                                        |       |     |       |
| Supplemental  Quarterly Data (Unaudited)                                                                                    |       | 90       |       |

 

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**MANAGEMENT’S REPORT ON INTERNALCONTROL OVER FINANCIAL REPORTING**

 

Our management is responsible for establishing and maintaining adequateinternal control over financial reporting. Our internal control over financial reporting is a process designedunder the supervision of our Chief Executive Officer and Chief FinancialOfficer to provide reasonable assurance regarding the reliability of financialreporting and the preparation of consolidated financial statements for externalpurposes in accordance with accounting principles generally accepted in theUnited States.

 

Because of its inherent limitations, internal control over financialreporting may not detect or prevent misstatements.  Projections of any evaluation of theeffectiveness to future periods are subject to risk that controls may becomeinadequate because of changes in conditions, or that the degree of compliancewith the policies or processes may deteriorate.

 

As of December 31, 2007,our management assessed the effectiveness of the Company’s internal controlover financial reporting based on the criteria for effective internal controlover financial reporting established in *Internal Control —Integrated Framework*, issued by the Committee of SponsoringOrganizations of the Treadway Commission. Based on the assessment, management determined that we maintainedeffective internal control over financial reporting as of December 31, 2007,based on those criteria.  The Companyacquired oil and gas properties fromDominion Resources, Inc. in August 2007 (“Dominion Acquisition”) andexcluded from our assessment of the effectiveness of internal control overfinancial reporting as of December 31, 2007, Dominion Acquisition’sinternal control over financial reporting associated with total assets of $2.2billion and total revenues of $106.1 million included in the consolidatedfinancial statements of the Company as of and for the year ended December 31,2007.

 

KPMG LLP, the independentregistered public accounting firm that audited the consolidated financial statementsof the Company included in this Annual Report on Form 10-K, has issued anattestation report on the effectiveness of the Company’s internal control overfinancial reporting as of December 31, 2007, which is includedherein.

 

/s/ Linn Energy,LLC

 

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**REPORT OF INDEPENDENT REGISTEREDPUBLIC ACCOUNTING FIRM**

 

TheBoard of Directors and UnitholdersLinn Energy, LLC:

 

We have audited theaccompanying consolidated balance sheets of Linn Energy, LLC and subsidiariesas of December 31, 2007 and 2006, and the related consolidated statementsof operations, unitholders’ capital (deficit), and cash flows for each of theyears in the three-year period ended December 31, 2007.  These consolidated financial statements arethe responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidatedfinancial statements based on our audits.

 

We conducted our auditsin accordance with the standards of the Public Company Accounting OversightBoard (United States).  Thosestandards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of materialmisstatement.  An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements.  An audit alsoincludes assessing the accounting principles used and significant estimatesmade by management, as well as evaluating the overall financial statementpresentation.  We believe that our auditsprovide a reasonable basis for our opinion.

 

In our opinion, theconsolidated financial statements referred to above present fairly, in allmaterial respects, the financial position of Linn Energy, LLC and subsidiariesas of December 31, 2007 and 2006, and the results of their operations andtheir cash flows for each of the years in the three-year period ended December 31,2007, in conformity with U.S. generally accepted accounting principles.

 

We also have audited, in accordance with the standards of the PublicCompany Accounting Oversight Board (United States), Linn Energy, LLC’sinternal control over financial reporting as of December 31, 2007, basedon criteria established in *Internal Control*—*Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO), and our report dated February 28,2008 expressed an unqualified opinion on the effectiveness of the Company’sinternal control over financial reporting.

 

/s/ KPMG LLP

 

Houston, Texas

February 28, 2008

 

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**REPORT OF INDEPENDENT REGISTEREDPUBLIC ACCOUNTING FIRM**

 

The Board of Directors and Unitholders

Linn Energy, LLC:

 

We have audited LinnEnergy, LLC’s internal control over financial reporting as of December 31,2007, based on criteria established in *Internal Control—IntegratedFramework* issued by the Committee of Sponsoring Organizations of theTreadway Commission (COSO).  Linn Energy,LLC’s management is responsible for maintaining effective internal control overfinancial reporting and for its assessment of the effectiveness of internalcontrol over financial reporting, included in the accompanying Management’sReport on Internal Control Over Financial Reporting.  Our responsibility is to express an opinionon the Company’s internal control over financial reporting based on our audit.

 

We conducted our audit inaccordance with the standards of the Public Company Accounting Oversight Board(United States).  Those standards requirethat we plan and perform the audit to obtain reasonable assurance about whethereffective internal control over financial reporting was maintained in allmaterial respects.  Our audit includedobtaining an understanding of internal control over financial reporting,assessing the risk that a material weakness exists, and testing and evaluatingthe design and operating effectiveness of internal control based on theassessed risk.  Our audit also includedperforming such other procedures as we considered necessary in the circumstances.  We believe that our audit provides areasonable basis for our opinion.

 

A company’s internalcontrol over financial reporting is a process designed to provide reasonableassurance regarding the reliability of financial reporting and the preparationof financial statements for external purposes in accordance with generallyaccepted accounting principles.  Acompany’s internal control over financial reporting includes those policies andprocedures that (1) pertain to the maintenance of records that, inreasonable detail, accurately and fairly reflect the transactions anddispositions of the assets of the company; (2) provide reasonableassurance that transactions are recorded as necessary to permit preparation offinancial statements in accordance with generally accepted accountingprinciples, and that receipts and expenditures of the company are being madeonly in accordance with authorizations of management and directors of thecompany; and (3) provide reasonable assurance regarding prevention or timelydetection of unauthorized acquisition, use, or disposition of the company’sassets that could have a material effect on the financial statements.

 

Because of its inherentlimitations, internal control over financial reporting may not prevent ordetect misstatements. Also, projections of any evaluation of effectiveness tofuture periods are subject to the risk that controls may become inadequatebecause of changes in conditions, or that the degree of compliance with thepolicies or procedures may deteriorate.

 

In our opinion, LinnEnergy, LLC maintained, in all material respects, effective internal controlover financial reporting as of December 31, 2007, based on criteriaestablished in *Internal Control—Integrated Framework*issued by the Committee of Sponsoring Organizations of the Treadway Commission.

 

Linn Energy, LLC’smanagement, in conducting its assessment of internal control over financialreporting as of December 31, 2007, has excluded its oil and gas propertiesand related assets in the Mid-Continent, which were acquired on August 31,2007 from Dominion Resources, Inc. and certain affiliates (Dominion), aspermitted by the Securities and Exchange Commission. Dominion’s total assetswere $2.2 billion, or approximately 59% of Linn Energy, LLC’s total assets, asof December 31, 2007, and Dominion’s total revenues were $106.1 million,or approximately 33% of Linn Energy, LLC’s total oil, gas and natural gasliquid sales, for the year ended December 31, 2007.  Our audit of internal control over financialreporting of Linn Energy, LLC also excluded an evaluation of the internalcontrol over financial reporting of Dominion.

 

We also have audited, in accordance with the standardsthe Public Company Accounting Oversight Board (United States), the consolidatedbalance sheets of Linn Energy, LLC as of December 31, 2007 and 2006, andthe related consolidated statements of operations, unitholders’ capital (deficit)and cash flows for each of the years in the three-year period ended December 31,2007, and our report dated February 28, 2008 expressed an unqualifiedopinion on those consolidated financial statements.

 

/s/ KPMG LLP

 

Houston, Texas

February 28, 2008

 

55

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**LINN ENERGY, LLC**

 

**CONSOLIDATEDBALANCE SHEETS**

 
| ** **                                                                                                      | ** ** | **December 31,**                    | ** ** |
|-----------------------------------------------------------------------------------------------------------------|------------|------------------------------------------|------------|
| ** **                                                                                                      | ** ** | **2007**                                 | ** ** | **2006** | ** ** |
| ** **                                                                                                      | ** ** | **(in thousands,  except unit amounts)** | ** ** |
| **Assets**                                                                                                      | ** ** | ** **                               | ** ** | ** ** | ** ** |
| **Current  assets:**                                                                                            | ** ** | ** **                               | ** ** | ** ** | ** ** |
| Cash and cash  equivalents                                                                                      |       | $                                        | 1,441      |   | $ | 6,595 |   |
| Accounts  receivable — trade, net                                                                          |       | 138,716                                  |       | 19,124 |   |
| Inventories                                                                                                     |       | 2,350                                    |       | 578 |   |
| Derivative  instruments                                                                                         |       | 26,100                                   |       | 37,353 |   |
| Other current  assets                                                                                           |       | 3,418                                    |       | 5,562 |   |
| Total current  assets                                                                                           |       | 172,025                                  |       | 69,212 |   |
| ** **                                                                                                      | ** ** | ** **                               | ** ** | ** ** | ** ** |
| **Oil and  gas properties and equipment**(successful efforts method)                                            |       | 3,618,741                                |       | 766,638 |   |
| Less accumulated  depreciation, depletion and amortization                                                      |       | (127,265                                 | )          | (33,349 | ) |
|                                                                                                            |       | 3,491,476                                |       | 733,289 |   |
|                                                                                                            |       |                                     |       |   |   |
| **Property  and equipment, net**                                                                                |       | 32,024                                   |       | 20,754 |   |
| ** **                                                                                                      | ** ** | ** **                               | ** ** | ** ** | ** ** |
| **Other  noncurrent assets:**                                                                                   |       |                                     |       |   |   |
| Deposit for oil  and gas properties                                                                             |       | 27,619                                   |       | 20,086 |   |
| Derivative  instruments                                                                                         |       | —                                   |       | 60,503 |   |
| Goodwill                                                                                                        |       | 64,419                                   |       | — |   |
| Other noncurrent  assets, net                                                                                   |       | 9,006                                    |       | 2,068 |   |
|                                                                                                            |       | 101,044                                  |       | 82,657 |   |
| Total assets                                                                                                    |       | $                                        | 3,796,569  |   | $ | 905,912 |   |
|                                                                                                            |       |                                     |       |   |   |
| **Liabilities and Unitholders’ Capital**                                                                   | ** ** | ** **                               | ** ** | ** ** | ** ** |
| **Current  liabilities:**                                                                                       | ** ** | ** **                               | ** ** | ** ** | ** ** |
| Accounts payable  and accrued expenses                                                                          |       | $                                        | 162,058    |   | $ | 12,759 |   |
| Joint interest  payable                                                                                         |       | 50,444                                   |       | 1,839 |   |
| Accrued interest  payable                                                                                       |       | 5,802                                    |       | 2,084 |   |
| Derivative  instruments                                                                                         |       | 6,148                                    |       | — |   |
| Other current  liabilities                                                                                      |       | 7,141                                    |       | 873 |   |
| Total current  liabilities                                                                                      |       | 231,593                                  |       | 17,555 |   |
|                                                                                                            |       |                                     |       |   |   |
| **Noncurrent  liabilities:**                                                                                    | ** ** | ** **                               | ** ** | ** ** | ** ** |
| Credit facility                                                                                                 |       | 1,443,000                                |       | 425,750 |   |
| Derivative  instruments                                                                                         |       | 63,813                                   |       | 423 |   |
| Asset retirement  obligations                                                                                   |       | 29,073                                   |       | 8,594 |   |
| Other noncurrent  liabilities                                                                                   |       | 2,449                                    |       | 2,636 |   |
| Total noncurrent  liabilities                                                                                   |       | 1,538,335                                |       | 437,403 |   |
| ** **                                                                                                      | ** ** | ** **                               | ** ** | ** ** | ** ** |
| **Unitholders’  capital:**                                                                                 | ** ** | ** **                               | ** ** | ** ** | ** ** |
| 113,815,914 units and 33,617,187 units issued and outstanding at  December 31, 2007 and 2006, respectively |       | 2,374,660                                |       | 246,034 |   |
| 9,185,965 Class B units issued and outstanding at  December 31, 2006                                  |       | —                                   |       | 188,590 |   |
| Accumulated  income (loss)                                                                                      |       | (348,019                                 | )          | 16,330 |   |
|                                                                                                            |       | 2,026,641                                |       | 450,954 |   |
| Total  liabilities and unitholders’ capital                                                                |       | $                                        | 3,796,569  |   | $ | 905,912 |   |

 

*The accompanying notes are anintegral part of these consolidated financial statements.*

 

56

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**LINN ENERGY, LLC**

 

**CONSOLIDATEDSTATEMENTS OF OPERATIONS**

 
| ** **                                    | ** ** | **Year Ended December 31,**            | ** ** |
|-----------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                    | ** ** | **2007**                                    | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                    | ** ** | **(in thousands, except per unit amounts)** | ** ** |
| **Revenues:**                                 | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil, gas and  natural gas liquid sales        |       | $                                           | 318,226    |   | $ | 80,393 |   | $ | 44,645 |   |
| Gain (loss) on  oil and gas derivatives       |       | (345,537                                    | )          | 103,308 |   | (76,193 | ) |
| Natural gas  marketing revenues               |       | 15,537                                      |       | 5,598 |   | 4,722 |   |
| Other revenues                                |       | 4,537                                       |       | 1,759 |   | 345 |   |
|                                          |       | (7,237                                      | )          | 191,058 |   | (26,481 | ) |
| **Expenses:**                                 | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Operating  expenses                           |       | 88,527                                      |       | 18,099 |   | 7,356 |   |
| Natural gas  marketing expenses               |       | 12,596                                      |       | 4,862 |   | 4,401 |   |
| General and  administrative expenses          |       | 57,188                                      |       | 39,993 |   | 3,332 |   |
| Data license  expenses                        |       | 3,231                                       |       | — |   | — |   |
| Depreciation,  depletion and amortization     |       | 97,964                                      |       | 24,173 |   | 7,294 |   |
|                                          |       | 259,506                                     |       | 87,127 |   | 22,383 |   |
|                                          |       | (266,743                                    | )          | 103,931 |   | (48,864 | ) |
| **Other income and (expenses):**              | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Interest  expense, net of amounts capitalized |       | (62,130                                     | )          | (25,857 | ) | (8,043 | ) |
| Gain (loss) on  interest rate swaps           |       | (28,081                                     | )          | 363 |   | 1,003 |   |
| Other expenses,  net                          |       | (3,822                                      | )          | (2,654 | ) | (373 | ) |
|                                          |       | (94,033                                     | )          | (28,148 | ) | (7,413 | ) |
| Income (loss) before income taxes             |       | (360,776                                    | )          | 75,783 |   | (56,277 | ) |
| Income tax  benefit (provision)               |       | (3,573                                      | )          | 3,402 |   | (74 | ) |
| Net income  (loss)                            |       | $                                           | (364,349   | ) | $ | 79,185 |   | $ | (56,351 | ) |
| ** **                                    | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Net income (loss) per unit:**               | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Units — basic                            |       | $                                           | (5.29      | ) | $ | 2.64 |   | $ | (2.75 | ) |
| Units — diluted                          |       | $                                           | (5.29      | ) | $ | 2.61 |   | $ | (2.75 | ) |
|                                          |       |                                        |       |   |   |   |   |
| Class B  units — basic              |       | $                                           | —     |   | $ | 2.64 |   | $ | — |   |
| Class B  units — diluted            |       | $                                           | —     |   | $ | 2.61 |   | $ | — |   |
|                                          |       |                                        |       |   |   |   |   |
| **Weighted average units outstanding:**       | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Units — basic                            |       | 68,916                                      |       | 28,281 |   | 20,518 |   |
| Units — diluted                          |       | 68,916                                      |       | 30,385 |   | 20,518 |   |
|                                          |       |                                        |       |   |   |   |   |
| Class B  units — basic              |       | —                                      |       | 1,737 |   | — |   |
| Class B  units — diluted            |       | —                                      |       | 1,737 |   | — |   |
|                                          |       |                                        |       |   |   |   |   |
| Distributions declared per unit               |       | $                                           | 2.18       |   | $ | 1.15 |   | $ | — |   |

 

*The accompanying notes are anintegral part of these consolidated financial statements.*

 

57

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**LINN ENERGY, LLC**

 

**CONSOLIDATEDSTATEMENTS OF UNITHOLDERS’ CAPITAL (DEFICIT)**

 
| ** **                                                                     | ** ** | **Unitholders’  Capital** | ** ** | **Accumulated  Income  (Loss)** | ** ** | **Treasury  Units  (at Cost)** | ** ** | **Total  Unitholders’  Capital  (Deficit)** | ** ** |
|--------------------------------------------------------------------------------|------------|--------------------------------|------------|---------------------------------|------------|--------------------------------|------------|--------------------------------------------------|------------|
| ** **                                                                     | ** ** | **(in thousands)**             | ** ** |
| ** **                                                                     | ** ** | ** **                     | ** ** | ** **                      | ** ** | ** **                     | ** ** | ** **                                       | ** ** |
| **Balance as of December 31, 2004**                                       |       | $                              | 16,024     |                            | $          | (6,504                         | )          | $                                                | —     |   | $ | 9,520 |   |
| Net loss                                                                       |       | —                         |       | (56,351                         | )          | —                         |       | (56,351                                          | )          |
| **Balance as of December 31, 2005**                                       |       | 16,024                         |       | (62,855                         | )          | —                         |       | (46,831                                          | )          |
| Sale of initial  public offering units, net of offering expense of $4,339 |       | 225,139                        |       | —                          |       | 13,671                         |       | 238,810                                          |       |
| Sale of private  placement units, net of expense of $348                       |       | 304,652                        |       | —                          |       | —                         |       | 304,652                                          |       |
| Redemption of  member units                                                    |       | —                         |       | —                          |       | (114,449                       | )          | (114,449                                         | )          |
| Cancellation of  member units                                                  |       | (100,778                       | )          | —                          |       | 100,778                        |       | —                                           |       |
| Distribution to  members                                                       |       | (32,056                        | )          | —                          |       | —                         |       | (32,056                                          | )          |
| Unit-based  compensation expense                                               |       | 21,643                         |       | —                          |       | —                         |       | 21,643                                           |       |
| Net income                                                                     |       | —                         |       | 79,185                          |       | —                         |       | 79,185                                           |       |
| **Balance as of December 31, 2006**                                       |       | 434,624                        |       | 16,330                          |       | —                         |       | 450,954                                          |       |
| Sale of private  placement units, net of expense of $34,334                    |       | 2,085,666                      |       | —                          |       | —                         |       | 2,085,666                                        |       |
| Issuance of  units                                                             |       | 2,842                          |       | —                          |       | —                         |       | 2,842                                            |       |
| Purchase of  units                                                             |       | —                         |       | —                          |       | (7,399                         | )          | (7,399                                           | )          |
| Cancellation of  member units                                                  |       | (7,399                         | )          | —                          |       | 7,399                          |       | —                                           |       |
| Distribution to  members                                                       |       | (154,963                       | )          | —                          |       | —                         |       | (154,963                                         | )          |
| Unit-based  compensation and unit warrant expense                              |       | 13,921                         |       | —                          |       | —                         |       | 13,921                                           |       |
| Exercise of unit  options                                                      |       | (31                            | )          | —                          |       | —                         |       | (31                                              | )          |
| Net loss                                                                       |       | —                         |       | (364,349                        | )          | —                         |       | (364,349                                         | )          |
| **Balance as of December 31, 2007**                                       |       | $                              | 2,374,660  |                            | $          | (348,019                       | )          | $                                                | —     |   | $ | 2,026,641 |   |

 

*The accompanying notes are anintegral part of these consolidated financial statements.*

 

58

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**LINN ENERGY, LLC**

 

**CONSOLIDATEDSTATEMENTS OF CASH FLOWS**

 
| ** **                                                                                               | ** ** | **Year Ended December 31** | ** ** |
|----------------------------------------------------------------------------------------------------------|------------|---------------------------------|------------|
| ** **                                                                                               | ** ** | **2007**                        | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                                                               | ** ** | **(in thousands)**              | ** ** |
| **Cash flow from operating activities:**                                                                 |       |                            |       |   |   |   |   |
| Net income  (loss)                                                                                       |       | $                               | (364,349   | ) | $ | 79,185 |   | $ | (56,351 | ) |
| **Adjustments  to reconcile net income (loss) to net cash provided by (used in) operating  activities:** | ** ** | ** **                      | ** ** | ** ** | ** ** | ** ** | ** ** |
| Depreciation,  depletion and amortization                                                                |       | 97,964                          |       | 24,173 |   | 7,294 |   |
| Amortization and  write-off of deferred financing fees and other                                         |       | 5,142                           |       | 4,548 |   | 875 |   |
| Accretion of  asset retirement obligation                                                                |       | 1,014                           |       | 314 |   | 172 |   |
| Unit-based  compensation and unit warrant expense                                                        |       | 13,921                          |       | 21,643 |   | — |   |
| Deferred income  tax                                                                                     |       | 3,360                           |       | (3,434 | ) | — |   |
| **Mark-to-market  on derivatives:**                                                                      | ** ** | ** **                      | ** ** | ** ** | ** ** | ** ** | ** ** |
| Total (gains) losses                                                                                     |       | 373,618                         |       | (103,390 | ) | 75,207 |   |
| Cash settlements                                                                                         |       | 40,784                          |       | 20,442 |   | (51,417 | ) |
| **Premiums  paid for derivatives**                                                                       |       | (279,313                        | )          | (49,807 | ) | (1,628 | ) |
| **Changes  in assets and liabilities:**                                                                  | ** ** | ** **                      | ** ** | ** ** | ** ** | ** ** | ** ** |
| Increase in  accounts receivable                                                                         |       | (106,227                        | )          | (371 | ) | (12,208 | ) |
| (Increase)  decrease in inventory and other assets                                                       |       | 3,286                           |       | 2,833 |   | (399 | ) |
| Increase  (decrease) in accounts payable and accrued expenses                                            |       | 104,709                         |       | 678 |   | 3,396 |   |
| Increase  (decrease) in joint interest payable                                                           |       | 48,605                          |       | (4,243 | ) | 3,589 |   |
| Increase in  accrued interest payable                                                                    |       | 3,718                           |       | 636 |   | 1,036 |   |
| Increase  (decrease) in other liabilities                                                                |       | 8,954                           |       | (12 | ) | 916 |   |
| Net cash used in  operating activities                                                                   |       | (44,814                         | )          | (6,805 | ) | (29,518 | ) |
| **Cash flow from investing activities:**                                                                 | ** ** | ** **                      | ** ** | ** ** | ** ** | ** ** | ** ** |
| Acquisition of  oil and gas properties                                                                   |       | (2,665,924                      | )          | (469,274 | ) | (122,065 | ) |
| Additions to oil  and gas properties                                                                     |       | (185,534                        | )          | (46,963 | ) | (27,145 | ) |
| Deposit for oil  and gas properties                                                                      |       | (27,610                         | )          | (20,086 | ) | — |   |
| Purchases of  property and equipment                                                                     |       | (17,890                         | )          | (15,414 | ) | (1,639 | ) |
| Proceeds from  sales of property and equipment                                                           |       | 4,538                           |       | — |   | — |   |
| Other investing  activities                                                                              |       | —                          |       | 106 |   | (49 | ) |
| Net cash used in  investing activities                                                                   |       | (2,892,420                      | )          | (551,631 | ) | (150,898 | ) |
| **Cash flow from financing activities:**                                                                 | ** ** | ** **                      | ** ** | ** ** | ** ** | ** ** | ** ** |
| Proceeds from  sale of units                                                                             |       | 2,120,000                       |       | 548,149 |   | — |   |
| Redemption of  member units                                                                              |       | (7,399                          | )          | (114,449 | ) | — |   |
| Proceeds from  issuance of debt                                                                          |       | 1,298,000                       |       | 584,000 |   | 275,295 |   |
| Principal  payments on debt                                                                              |       | (283,108                        | )          | (425,743 | ) | (80,690 | ) |
| Distribution to  members                                                                                 |       | (154,963                        | )          | (32,056 | ) | — |   |
| Offering costs                                                                                           |       | (34,334                         | )          | (1,210 | ) | (3,532 | ) |
| Financing fees  and other                                                                                |       | (6,116                          | )          | (4,701 | ) | (1,804 | ) |
| Net cash  provided by financing activities                                                               |       | 2,932,080                       |       | 553,990 |   | 189,269 |   |
| **Net increase (decrease) in cash and cash  equivalents**                                                |       | (5,154                          | )          | (4,446 | ) | 8,853 |   |
| **Cash and cash equivalents:**                                                                           | ** ** | ** **                      | ** ** | ** ** | ** ** | ** ** | ** ** |
| Beginning                                                                                                |       | 6,595                           |       | 11,041 |   | 2,188 |   |
| Ending                                                                                                   |       | $                               | 1,441      |   | $ | 6,595 |   | $ | 11,041 |   |

 

*The accompanying notes are anintegral part of these consolidated financial statements.*

 

59

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**LINN ENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**(1)****                                ****Basis of Presentation and SignificantAccounting Policies**

 

***(a)******                                ******Natureof Business***

Linn Energy, LLC (“Linn Energy” or the “Company”) is an independent oiland gas company focused on the development and acquisition of long lifeproperties which complement its asset profile in producing basins within theUnited States.  Linn Energy beganoperations in March 2003 and was formed as a Delaware limited liabilitycompany in April 2005.  The Companycompleted its initial public offering (“IPO”) in January 2006 and itsunits representing limited liability company interests (“units”) are listed onThe NASDAQ Global Select Market under the symbol “LINE.”

 

***(b)******                                ******Principlesof Consolidation and Reporting***

The Company presents its financial statements in accordance with U.S.generally accepted accounting principles (“GAAP”).  The consolidated financial statements includethe accounts of the Company and its wholly owned subsidiaries.  All significant intercompany transactions andbalances have been eliminated upon consolidation.  Certain amounts in the consolidated financialstatements and notes thereto have been reclassified to conform to the 2007financial statement presentation.

 

***(c)******                                 ******Use ofEstimates***

Management of the Company has made a number of estimates andassumptions relating to the reporting of assets and liabilities and revenuesand expenses and the disclosure of contingent assets and liabilities to preparethese consolidated financial statements in conformity with GAAP.  Actual results could differ from thoseestimates.  The estimates that areparticularly significant to the financial statements include estimates of oil,gas and natural gas liquid (“NGL”) reserves, future cash flows from oil and gasproperties, depreciation, depletion and amortization, asset retirementobligations, the fair value of derivatives and unit-based compensation expense.

 

***(d)******                                ******CashEquivalents***

For purposes of the statement of cash flows, the Company considers allhighly liquid short-term investments with original maturities of three monthsor less to be cash equivalents.

 

The Company manages its working capital and cash requirements to borrowonly as needed from its credit facility.  At December 31, 2007, the Company hadapproximately $5.2 million of outstanding checks, the balance of which is includedin other current liabilities on the consolidated balance sheet.

 

***(e)******                                 ******Inventories***

Materials, supplies and commodity inventories are valued at the lowerof average cost or market, determined by the first-in-first-out method.

 

***(f)******                                   ******Oiland Gas Properties/Property and Equipment***

*Proved Oil and Gas Properties*

 

The Company accounts for oil and gas properties under the successfulefforts method.  Under this method, allacquisition and development costs of proved properties are capitalized andamortized on a unit-of-production basis over the remaining life of the provedreserves and proved developed reserves, respectively.

 

The Company evaluates the impairment of its proved oiland gas properties on a field-by-field basis whenever events or changes incircumstances indicate an asset’s carrying amount may not be recoverable.  The carrying amount of proved oil and gasproperties are reduced to fair value when the expected undiscountedfuture cash flows are less than the asset’s net book value.  Cash flows are determined based upon reservesusing prices, costs and discount factors consistent with those used forinternal decision making.  The underlyingcommodity prices embedded in the Company’s estimated cash flows are the productof a process that begins with the Henry Hub forward curve pricing, adjusted forestimated location and quality differentials, as well as other factors thatmanagement believes will impact realizable prices.  Costs of retired, sold or abandoned properties

 

60

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**LINNENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****- Continued**

 

that constitute a part of anamortization base are charged or credited, net of proceeds, to accumulateddepreciation, depletion and amortization unless doing so significantly affectsthe unit-of-production amortization rate, in which case a gain or loss isrecognized currently.  Gains or lossesfrom the disposal of other properties are recognized currently.  Expenditures for maintenance and repairsnecessary to maintain properties in operating condition are expensed asincurred.  Major replacements arecapitalized.  Estimated dismantlement andabandonment costs for oil and gas properties are capitalized at their estimatednet present value and amortized on a unit-of-production basis over theremaining life of the related proved developed reserves.

 

The Company recorded impairment on oil and gasproperties of approximately $3.3 million and $1.0 million for the years ended December 31,2007 and 2006, respectively, which is included in depreciation, depletion andamortization expense on the consolidated statements of operations.

 

*Unproved Oil and Gas Properties*

Unproved properties consistof costs incurred to acquire unproved leasehold as well as costs incurred toacquire unproved resources.  Unprovedleasehold costs are capitalized and amortized on a composite basis ifindividually insignificant, based on past success, experience and averagelease-term lives.  Unamortized leaseholdcosts related to successful exploratory drilling are reclassified to provedproperties and depleted on a unit-of-production basis.  The carrying value of the Company’s unprovedresources, which were acquired in connection with business acquisitions, wasdetermined using themarket-based weighted average cost of capital rate, subjected to additionalproject-specific risking factors.  Because thesereserves do not meet the definition of proved reserves, the related costs arenot classified as proved properties.  Asthe unproved resources are developed and proven, the associated costs arereclassified to proved properties and depleted on a unit-of-productionbasis.  The Company assesses unprovedresources for impairment annually by comparing book value to fair value, whichis determined using discounted estimates of future cash flows.

 

*Other Property and Equipment*

Other property and equipmentincludes gas gathering systems, pipelines, buildings, data processing andtelecommunication equipment, office furniture and equipment, and other fixedassets.  These items are recorded at costand are depreciated using the straight-line method based on expected livesranging from 3 to 39 years for the individual asset or group of assets.

 

***(g)******                                ******Goodwill***

Goodwill represents the excess of the cost of an acquired business overthe net amounts assigned to assets acquired and liabilities assumed.  The Company accounts for goodwill inaccordance with SFAS No. 142, *“Goodwill and OtherIntangible Assets.”*  Goodwillis not amortized to earnings but is tested annually during the fourth quarteror whenever events or changes in circumstances indicate that the carrying valuemay not be recoverable (see Note 3).

 

***(h)******                                ******RevenueRecognition***

Sales of oil and gas and NGL are recognized when oil, gas or NGL hasbeen delivered to a custody transfer point, persuasive evidence of a salesarrangement exists, the rights and responsibility of ownership pass to thepurchaser upon delivery, collection of revenue from the sale is reasonablyassured, and the sales price is fixed or determinable.  Virtually all of the Company’s contractpricing provisions are tied to a market index, with certain adjustments basedon, among other factors, whether a well delivers to a gathering or transmissionline, quality of oil, gas and NGL, and prevailing supply and demand conditions,so that prices fluctuate to remain competitive with other available suppliers.

 

Revenues arepresented on a gross basis on the consolidated statements of operations.  Production taxes are included in operatingexpenses on the consolidated statements of operations and were approximately$17.8 million, $2.0 million and $0.7 million for the years ended December 31,2007, 2006 and 2005, respectively.

 

61

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**LINNENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****- Continued**

 

The Company has elected the entitlements method to account for gasimbalances.  Gas imbalances occur whenthe Company sells more or less than its entitled ownership percentage of totalgas production.  Under the entitlementsmethod, any amount received in excess of the Company’s share is treated as aliability.  If the Company receives lessthan its entitled share, the underproduction is recorded as a receivable.  At December 31, 2007, the Company had agas imbalance receivable of approximately $6.6 million, which is included inaccounts receivable — trade, net, on the consolidated balance sheet.  The Company did not have any significant gasimbalance positions at December 31, 2006.

 

The Company engages in the purchase, gathering and transportation ofthird-party natural gas and subsequently markets such gas to independentpurchasers under separate arrangements. As such, the Company separately reports third-party marketing sales andnatural gas marketing expenses.

 

The Company generates electricity with excess gas, which it uses toserve certain of its operating facilities in Brea, California.  Any excess electricity is sold to theCalifornia wholesale power market.  Theseamounts are included in other revenues on the consolidated statements ofoperations.

 

***(i)******                                   ******RestrictedCash***

Restricted cash of $0.5 million is included in other noncurrent assetson the consolidated balance sheet at December 31, 2007, and representscash the Company has deposited into a separate account and designated for assetretirement obligations in accordance with contractual agreements.

 

***(j)******                                   ******DerivativeInstruments***

The Company uses derivative financial instruments to achieve a morepredictable cash flow from its oil, gas and NGL production by reducing its exposureto price fluctuations.  As of December 31,2007, these transactions were in the form of swaps and puts.  Additionally, the Company uses derivativefinancial instruments in the form of interest rate swaps to mitigate itsinterest rate exposure.  The Companyaccounts for these activities pursuant to SFAS No. 133, “*Accounting for Derivative Instruments and HedgingActivities,”* as amended, (“SFAS 133”).  This statement establishes accounting andreporting standards requiring that derivative instruments (including certainderivative instruments embedded in other contracts) be recorded at fair valueand included in the balance sheet as assets or liabilities.

 

The Company accounts for its derivatives at fair value as an asset orliability and the change in the fair value of the derivatives is included inearnings since none of the Company’s commodity or interest rate derivatives aredesignated as hedges under the provisions of SFAS 133.   See Note 8 and Note 9 foradditional details about the Company’s derivative financial instruments.

 

***(k)******                                ******Unit-BasedCompensation***

SFAS No. 123 (revised 2004),*“Share-BasedPayment”* (“SFAS 123R”) requires the recognition of compensationexpense, over the requisite service period, in an amount equal to the fairvalue of unit-based payments granted to employees and non-employeedirectors.  The fair value of theunit-based payments, excluding liability awards, is computed at the date ofgrant and will not be remeasured.  Thefair value of liability awards is remeasured at each reporting date through thesettlement date with the change in fair value recognized as compensationexpense over that period.  The Companycurrently does not have any awards accounted for as liability awards.  SFAS 123R also requires the benefits oftax deductions in excess of recognized compensation costs to be reported asfinancing cash flow, rather than as an operating cash flow as required underprior guidance.  This requirement willreduce net operating cash flows and increase net financing cash flows in periodsin which such tax deduction exists.  TheCompany had no excess tax deductions for any periods presented.

 

The Company has made a policy decision, in accordance with theprovisions of SFAS 123R, to recognize compensation cost for service-basedawards on a straight-line basis over the requisite service period.  The Company did not issue any unit-basedcompensation awards prior to January 

 

62

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**LINNENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****- Continued**

 

2006.  See Note 6 for adiscussion of the Company’s accounting for unit-based compensation expense.

 

***(l)******                                   ******DeferredFinancing Fees***

The Company incurred legal and bank fees related to the issuance ofdebt (see Note 7).  At December 31,2007 and 2006, net deferred financing fees of approximately $8.3 million and$1.6 million, respectively, are included in other noncurrent assets on theconsolidated balance sheets.  These debtissuance costs are amortized over the life of the debt agreement.  For the years ended December 31, 2007,2006 and 2005, amortization expense of $1.5 million, $1.1 million and $0.5million, respectively, is included in interest expense on the consolidatedstatements of operations.  Deferredfinancing fees of approximately $2.8 million, $3.3 million and $0.4 millionwere written-off in connection with refinancings during the years ended December 31,2007, 2006 and 2005, respectively, and are included in other expenses, net onthe consolidated statements of operations.

 

***(m)******                             ******FairValue of Financial Instruments***

The carrying values of the Company’s receivables, payables and debt areestimated to be substantially the same as their fair values at December 31,2007 and 2006.  See Note 8 andNote 9 for details about the fair value of the Company’s derivativefinancial instruments.

 

***(n)******                                ******Unitholders’Capital***

The operations of the Company are governed by the provisions of alimited liability company agreement executed by and among its members.  The agreement includes specific provisionswith respect to the maintenance of the capital accounts of each of the Company’sunitholders.

 

Pursuant to applicable provisions of the Delaware Limited LiabilityCompany Act (the “Delaware Act”) and the Second Amended and Restated LimitedLiability Company Agreement of Linn Energy, LLC (the “Agreement”), unitholdershave no liability for the debts, obligations and liabilities of the Company,except as expressly required in the Agreement or the Delaware Act.  Pursuant to the terms of the Agreement,unitholders are entitled to vote on the following matters:

 
| · |   | the annual  election of the Company’s Board of Directors;                                        |
|--------|--------|-------------------------------------------------------------------------------------------------------|
| · |   | specified  amendments to the Agreement;                                                               |
| · |   | the merger of  the Company or the sale of all or substantially all of the Company’s assets;  and |
| · |   | the dissolution  of the Company.                                                                      |

 

The Company will remain in existence unless and until dissolved inaccordance with the terms of the Agreement.

 

***(o)******                                ******IncomeTaxes***

The Company is a limited liability company treated as a partnership forfederal and state income tax purposes with all income tax liabilities and/orbenefits of the Company being passed through to the unitholders.  As such, no recognition of federal or stateincome taxes for the Company or its subsidiaries that are organized as limitedliability companies have been provided for in the accompanying financialstatements, except as described below.

 

Certain of the Company’s subsidiaries are Subchapter C-corporationssubject to corporate income taxes, which are accounted for under the provisionsof SFAS No. 109 *“Accounting for IncomeTaxes”* (“SFAS 109”), which uses the asset and liabilitymethod.  Deferred tax assets andliabilities are recognized for the future tax consequences attributable todifferences between the financial statement carrying amounts of existing assetsand liabilities and their respective tax basis and operating loss and taxcredit carryforwards.  Deferred taxassets and liabilities are measured using enacted tax rates expected to applyto taxable income in the years in which those temporary differences areexpected to be recovered or settled.  Theeffect on deferred tax assets and liabilities 

 

63

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**LINNENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****- Continued**

 

of a change in tax rates is recognized in income in the period thatincludes the enactment date.  SeeNote 15 for detail of amounts recorded in consolidated financialstatements.

 

***(p)******                                ******RecentlyIssued Accounting Standards***

In December 2007, the FASBissued SFAS No. 141 (Revised 2007), *“Business Combinations”*(“SFAS 141R”).  Under Statement 141R, an acquiringentity will be required to recognize all the assets acquired and liabilitiesassumed at the acquisition date fair value with limited exceptions.  Statement 141R will change theaccounting treatment for certain specific items, including acquisition costs,which will be expensed as incurred, and acquired contingent liabilities, whichwill be recorded at fair value at the acquisition date.  SFAS 141R also includes new disclosure requirements.  SFAS 141R applies prospectively tobusiness combinations for which the acquisition date is on or after thebeginning of the first annual reporting period on or after December 15,2008, with earlier adoption prohibited.  The Company will implement SFAS 141R asrelated to acquisitions that occur after January 1, 2009.

 

In June 2007, the FinancialAccounting Standards Board (“FASB”) ratified the consensus in Emerging IssuesTask Force Issue 06-11 (“EITF 06-11”).  EITF 06-11 is effective for fiscal yearsbeginning after December 15, 2007 and requires, among other things,recognition as an increase to additional paid-in capital the realized incometax benefit from dividends or dividend equivalents that are paid to employeesand charged to retained earnings.  TheCompany does not believe that the adoption of EITF 06-11 will have amaterial impact on its results of operations or financial position.

 

In April 2007, the FASB issuedStaff Position No. 39-1, “*Amendment of FASBInterpretation No. 39*” (“FSP No. FIN 39-1”).  The terms “conditional contracts” and “exchangecontracts” have been replaced with the more general term “derivative contracts.”  In addition, FSP No. FIN 39-1permits the offsetting of recognized fair values for the right to reclaim cashcollateral or the obligation to return cash collateral against fair values ofderivatives under certain circumstances, such as under master nettingarrangements.  Additional disclosure isalso required regarding a company’s accounting policy with respect tooffsetting fair value amounts.  Theguidance in FSP No. FIN 39-1 is effective for fiscal years beginningafter November 15, 2007, with early application allowed.  The effects of initial adoption should berecognized as a change in accounting principle through retrospectiveapplication for all periods presented. At December 31, 2007, the Company changed its accounting policyrelated to the balance sheet presentation of derivative instruments.  In accordance with the provisions of FASBInterpretation No. 39, *“Offsetting of AmountsRelated to Certain Contracts,*” the Company presents derivativeinstruments on a net basis, when right of offset exists, in the consolidatedbalance sheets.  Amounts on theconsolidated balance sheet at December 31, 2006 were reclassified toconform to current year presentation.

 

In September 2006, the FASBissued SFAS No. 157, “*Fair Value Measurements*”(“SFAS 157”), which provides guidance for using fair value to measureassets and liabilities.  SFAS 157applies whenever other standards require (or permit) assets or liabilities tobe measured at fair value and clarifies that for items that are not activelytraded, such as certain kinds of derivatives, fair value should reflect theprice in a transaction with a market participant, including an adjustment forrisk, not just the mark-to-market value. SFAS 157 also requires expanded disclosure of the effect onearnings for items measured using unobservable data.  The provisions of SFAS 157 areapplicable to financial assets effective for financial statements issued forfiscal years beginning after November 15, 2007, and interim periods withinthose fiscal years, and are applicable to non-financial assets effective forfiscal years beginning after November 15, 2008.  The Company is currently evaluating theimpact the adoption of SFAS 157 will have on its results of operations andfinancial position.

 

64

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**LINNENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****- Continued**

 

**(2)****                                ****Acquisitions andDispositions**

 

The Company accounts for its acquisitions using the purchase method ofaccounting as prescribed in SFAS No. 141, *“BusinessCombinations.”*  The followingprovides a summary of the Company’s acquisitions during 2007 and 2006, as wellas acquisitions subsequent to December 31, 2007.

 

On February 1, 2007, effective January 1, 2007, the Companycompleted the acquisition of certain oil and gas properties and related assetsin the Mid-Continent from Stallion Energy LLC, acting as general partner forCavallo Energy, LP, for a contract price of $415.0 million (“Mid-Continent I”).  The Mid-Continent I acquisition wasfinanced with a combination of a private placement of units (see Note 4)and borrowings under the Company’s credit facility (see Note 7).

 

On June 12, 2007, effective April 1, 2007, the Companycompleted the acquisition of certain oil and gas properties in theMid-Continent for a contract price of $90.5 million (“Mid-Continent II”).  The acquisition was financed with borrowingsunder the Company’s credit facility (see Note 7).

 

On August 31, 2007, effective July 1, 2007, the Companycompleted the acquisition of certain oil and gas properties in theMid-Continent for a contract price of $2.05 billion from DominionResources, Inc. and certain affiliates (“Dominion”) (“Mid-Continent III”).  On August 31, 2007, the Companycompleted the private placement of $1.5 billion of units and Class Dunits to a group of institutional investors (see Note 4).  The Company funded the Mid-Continent IIIacquisition with the net proceeds from the private placement, together withborrowings under its credit facility (see Note 7).

 

The following presents the preliminary purchaseaccounting for the Mid-Continent I, Mid-Continent II andMid-Continent III acquisitions, based on estimates of fair value (estimatesof fair value for Mid-Continent III are preliminary):

 
| ** **                            | ** ** | **Mid-Continent  I** | ** ** | **Mid-Continent  II** | ** ** | **Mid-Continent  III** | ** ** |
|---------------------------------------|------------|----------------------|------------|-----------------------|------------|------------------------|------------|
| ** **                            | ** ** | **(in thousands)**   | ** ** |
|                                  |       |                 |       |                  |       |                   |       |
| Cash                                  |       | $                    | 411,287    |                  | $          | 90,179                 |       | $ | 2,022,606 |   |
| Estimated transaction costs           |       | 2,996                |       | 366                   |       | 10,140                 |       |
| Estimated pending closing adjustments |       | (363                 | )          | (1,440                | )          | 18,299                 |       |
|                                  |       | 413,920              |       | 89,105                |       | 2,051,045              |       |
| Fair value of liabilities assumed     |       | 1,706                |       | 1,034                 |       | 33,245                 |       |
| Total purchase  price                 |       | $                    | 415,626    |                  | $          | 90,139                 |       | $ | 2,084,290 |   |

 

The following presents the allocations of the purchaseprices for the Mid-Continent I, Mid-Continent II andMid-Continent III acquisitions based on estimates of fair value (estimatesof fair value for Mid-Continent III are preliminary):

 
| ** **                    | ** ** | **Mid-Continent  I** | ** ** | **Mid-Continent  II** | ** ** | **Mid-Continent  III** |   |
|-------------------------------|------------|----------------------|------------|-----------------------|------------|------------------------|--------|
| ** **                    | ** ** | **(in thousands)**   |       |
|                          |       |                 |       |                  |       |                   |   |
| Current assets                |       | $                    | —     |                  | $          | 644                    |   | $ | 12,831 |   |
| Oil and gas properties        |       | 414,888              |       | 89,495                |       | 2,003,179              |   |
| Property, plant and equipment |       | 738                  |       | —                |       | 3,861                  |   |
| Goodwill                      |       | —               |       | —                |       | 64,419                 |   |
|                          |       | $                    | 415,626    |                  | $          | 90,139                 |   | $ | 2,084,290 |   |

 

65

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**LINNENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****- Continued**

 

The purchase prices and purchase price allocationsabove are based on reserve reports, published market prices and estimates bymanagement.  The most significantassumptions are related to the estimated fair values assigned to proved oil andgas properties.  To estimate the fairvalues of these properties, the Company utilized preliminary estimates of oil,gas and NGL reserves prepared by the independent engineering firm, DeGolyer andMacNaughton.  The Company estimatedfuture prices to apply to the estimated reserve quantities acquired, andestimated future operating and development costs, to arrive at estimates offuture net revenues.  The Company alsoreviewed comparable purchases and sales of oil and gas properties within thesame regions.  The purchase prices andthe allocations of the purchase prices are preliminary.  Items pending III completion include finalclosing adjustments for all three acquisitions and for the Mid-Continent IIIacquisition include completion of independent appraisals of fixed assets, andadditional analysis related to the fair value of proved and unproved oil andgas reserves, including discounted cash flows and market-based data.  The purchase prices and purchase priceallocations will be finalized within one year of the acquisition dates.

 

The following unaudited pro forma financialinformation presents a summary of Linn Energy’s consolidated results ofoperations for the years ended December 31, 2007 and 2006, assuming theMid-Continent I, Mid-Continent II and Mid-Continent IIIacquisitions had been completed as of January 1, 2006, includingadjustments to reflect the allocation of the purchase prices to the acquirednet assets.  The pro forma financial informationalso assumes that the acquisitions of California assets from affiliatedentities of Blacksand Energy, LLC and Oklahoma assets from Kaiser-Francis OilCompany were completed as of January 1, 2006.  The California and Oklahoma acquisitions werecompleted in 2006 and the revenues and expenses are included in theconsolidated results of the Company effective August 1, 2006 and September 1,2006, respectively.  The revenues andexpenses of the Mid-Continent I and Mid-Continent II assets areincluded in the consolidated results of the Company as of February 1, 2007and June 12, 2007, respectively. The revenues and expenses of the Mid-Continent III assets are includedin the consolidated results of the Company effective September 1,2007.  The pro forma financialinformation is not necessarily indicative of the results of operations if theacquisitions had been effective as of these dates.

 
| ** **                         | ** ** | **Years Ended  December 31,**          | ** ** |
|------------------------------------|------------|---------------------------------------------|------------|
| ** **                         | ** ** | **2007**                                    | ** ** | **2006** | ** ** |
| ** **                         | ** ** | **(in thousands, except per unit amounts)** | ** ** |
|                               |       |                                        |       |   |   |
| Total revenues                     |       | $                                           | 219,656    |   | $ | 659,180 |   |
| Total operating expenses           |       | $                                           | 385,709    |   | $ | 332,932 |   |
| Net income (loss)                  |       | $                                           | (294,600   | ) | $ | 230,128 |   |
|                               |       |                                        |       |   |   |
| Net income (loss) per unit:        |       |                                        |       |   |   |
| Units — basic                 |       | $                                           | (4.27      | ) | $ | 2.95 |   |
| Units — diluted               |       | $                                           | (4.27      | ) | $ | 2.94 |   |
|                               |       |                                        |       |   |   |
| Class B  units — basic   |       | $                                           | —     |   | $ | 2.95 |   |
| Class B  units — diluted |       | $                                           | —     |   | $ | 2.94 |   |

 

The unaudited proforma condensed combined statements of operations present net income (loss) perunit allocated to the units and the Class B units on an equal basis forthe year ended December 31, 2006. In January 2007 the Class B units were converted into units ona one-to-one basis; therefore, pro forma net income (loss) per unit assumesthat the units and Class B units share equally in the pro forma net income(loss) of the Company.  See Note 4for additional details.

 

In addition, during 2007, the Company completed thefollowing other transactions:

 
| · | January 2007 — gas properties located in the  Appalachian Basin for a contract price of $39.0 million |
|--------|-----------------------------------------------------------------------------------------------------------------|

 

66

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**LINNENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****- Continued**

 
| · | March 2007 — sold certain oil and gas  properties located in New York for cash of approximately $2.5 million  and recorded a gain of approximately $0.9 million; the gain is included in  other revenues on the consolidated statements of operations |
|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                                                                 |
| · | April 2007 — net profits interest in oil and  gas properties in California for a contract price of $10.0 million                                                                                                                                           |
|   |                                                                                                                                                                                                                                                                 |
| · | October 2007 — oil and gas properties located  in the Mid-Continent for a contract price of $22.5 million                                                                                                                                                  |
|   |                                                                                                                                                                                                                                                                 |
| · | October 2007 — asset acquisition of a royalty  interest in oil and gas properties located primarily in the Mid-Continent for  a contract price of $52.0 million                                                                                            |

 

***Subsequent Event — Acquisitions***

 

On January 31, 2008, the Company completedthe acquisition of certain oil and gas properties, effective October 1,2007, located primarily in the Mid-Continent region from Lamamco DrillingCompany (“Lamamco”) for a contract price of $552.2 million, subject to purchaseprice adjustments (“Mid-Continent IV”).  The purchase price includes a payment of$27.6 million paid by the Company to the seller in December 2007.  At December 31, 2007, this amount isreported separately on the consolidated balance sheet within other noncurrent assets,along with related acquisition costs incurred prior to year end.  Theacquisition was financed with a combination of borrowings under the Company’scredit facility and proceeds from a term loan entered into at closing (seeNote 7).

 

The following presents the preliminary purchaseaccounting for the Mid-Continent IV acquisition, based on preliminary estimatesof fair value:

 
| ** **                                  | ** ** | **Mid-Continent  IV** | ** ** |
|---------------------------------------------|------------|-----------------------|------------|
| ** **                                  | ** ** | **(in thousands)**    | ** ** |
|                                        |       |                  |       |
| Cash                                        |       | $                     | 547,325    |   |
| Estimated transaction costs and adjustments |       | (3,955                | )          |
|                                        |       | 543,370               |       |
| Fair value of liabilities assumed           |       | 1,825                 |       |
| Total purchase  price                       |       | $                     | 545,195    |   |

 

The following presents the preliminary allocations ofthe purchase price for the Mid-Continent IV acquisition, based on preliminaryestimates of fair value:

 
| ** **                            | ** ** | **Mid-Continent  IV** | ** ** |
|---------------------------------------|------------|-----------------------|------------|
| ** **                            | ** ** | **(in thousands)**    | ** ** |
|                                  |       |                  |       |
| Current assets                        |       | $                     | 8,064      |   |
| Oil and gas properties                |       | 537,605               |       |
| Property, plant and equipment         |       | 469                   |       |
| Accounts payable and accrued expenses |       | (943                  | )          |
|                                  |       | $                     | 545,195    |   |

 

The preliminary purchase price allocation is based onpreliminary information and estimates by management as final appraisals ofassets acquired and liabilities assumed are not yet complete.  The purchase price allocation will becompleted within one year of the acquisition date.  In January 2008, the 

 

67

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**LINNENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****- Continued**

 

Company also acquired gas properties located in theAppalachian Basin for contract consideration of 600,000 units (equal to a fairvalue of approximately $14.7 million), subject to purchase price adjustments.

 

**(3)****                                ****Goodwill**

 

The entire goodwill balance of $64.4 million at December 31, 2007is related to the Mid-Continent III acquisition in August 2007 (seeNote 2).  The goodwill is associatedwith the Company gaining a significant interest in the Mid-Continent region,increasing its opportunity for growth and enhancing its position as a leadingNorth American oil and gas producer.  TheCompany also obtained the expertise of an experienced workforce, increasedpurchasing power and gained greater marketing flexibility in optimizing salesand accessing key market information. The Company is a limited liability company and treated as a partnershipfor tax purposes (see Note 15); therefore, for tax purposes, the goodwill isnot deductible by the Company.

 

The provisions of SFAS No. 142 require that a two-stepimpairment test be performed annually or whenever events or changes incircumstances indicate that the carrying value of an asset may not berecoverable.  The first step of the testfor impairment compares the book value of the Company’s reporting unit to itsestimated fair value.  The second step ofthe goodwill impairment test, which is only required when the net book value ofthe reporting unit exceeds the fair value, compares the implied fair value ofgoodwill to its book value to determine if an impairment is required.  The fair value is determined using acombination of the income approach and the market approach.  Under the income approach, the fair value isestimated based on the present value of expected future cash flows.  Under the market approach, the fair value isestimated based on market multiples of reserves and production for comparablecompanies as well as recent comparable transactions.

 

The income approach is dependent on a number of factors includingestimates of forecasted revenue and costs, proved reserves, as well as thesuccess of future development of unproved resources, appropriate discount ratesand other variables.  Downward revisionsof estimated reserve quantities, increases in future cost estimates,divestiture of a significant component or depressed oil, gas and NGL pricescould lead to an impairment of all or a portion of goodwill in future periods.  Under the market approach, the Company makescertain judgments about the selection of comparable companies, comparablerecent company and asset transactions and transaction premiums.  Although the Company bases its fair valueestimate on assumptions it believes to be reasonable, those assumptions areinherently unpredictable and uncertain.

 

The following reflects the changes in the carrying amount of goodwillduring the year:

 
| ** **                    | ** ** | **(in thousands)** | ** ** |
|-------------------------------|------------|--------------------|------------|
|                          |       |               |       |
| December 31, 2006        |       | $                  | —     |   |
| Mid-Continent III acquisition |       | 64,419             |       |
| December 31, 2007        |       | $                  | 64,419     |   |

 

**(4)****                                ****Unitholders’ Capital**

 

***Private Placements***

 

In August 2007, the Company closed its privateplacement of $1.5 billion of units to a group of institutional investors,consisting of 34,997,005 Class D units at a price of $30.97 per unit and12,999,989 units at a price of $32.00 per unit. Proceeds, net of expenses, were $1.48 billion and were used to fund the August 2007acquisition of certain oil and gas properties in the Mid-Continent (seeNote 2).  The Class D unitswere converted to units on a one-for-one basis in November 2007.

 

In June 2007,the Company closed its private placement of $260.0 million of units to a groupof institutionalinvestors, consisting of 7,761,194 units at a price of $33.50 per unit.  Proceeds, net of expenses, were $255.2 millionand were used to repay indebtedness under the Company’s Credit Facility.

 

68

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**LINNENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****- Continued**

 

In February 2007,the Company closed its private placement of $360.0 million of units to agroup of institutional investors, consisting of 7,465,946 Class C units at a priceof $25.06 per unit, and 6,650,144 units at a price of $26.00 per unit.  Proceeds, net of expenses, were$353.1 million and were used to finance the February 2007 acquisitionof certain oil and gas properties in Texas and the acquisitions of certain gasproperties in West Virginia (seeNote 2).  The Class Cunits were converted into units on a one-for-one basis in April 2007.

 

In October 2006, the Company closed its privateplacement of $305.0 million of units to a group of institutional investors,consisting of 9,185,965 Class B units at a price of $20.55 per unit, and5,534,687 units at a price of $21.00 per unit. Proceeds, net of expenses were $304.7 million and were used to repayindebtedness.  The Class B unitswere converted into units on a one-for-one basis in January 2007.

 

***Registrationof Units***

 

In connection with each of its private placements, theCompany agreed to file a Registration Statement with the SEC covering the unitsand underlying units.  RegistrationStatements covering all the units issued through the private placements notedabove were filed and declared effective by the SEC during December 2007.

 

In December 2007, the Company was required to paypurchasers in the June 2007 private placement approximately $0.7 millionin liquidated damages as specified in the registration rights agreement becausethe registration effectiveness deadline in the agreement was not achieved.  This payment is included in general andadministrative expenses on the consolidated statement of operations for theyear ended December 31, 2007.

 

***Distributions***

 

Underthe limited liability company agreement, Company unitholders are entitled to receivea quarterly distribution of available cash to the extent there is sufficientcash from operations after establishment of cash reserves and payment of feesand expenses.  The following provides asummary of distributions paid by the Company during the years ended December 31,2007 and 2006:

 
| **Date Paid**      | ** ** | **Period Covered by Distribution**      | ** ** | **Distribution  Per Unit** | ** ** | **Total  Distribution** | ** ** |
|--------------------|------------|-----------------------------------------|------------|----------------------------|------------|-------------------------|------------|
| ** **         | ** ** | ** **                              | ** ** | ** **                 | ** ** | **(in thousands)**      | ** ** |
|               |       |                                    |       |                       |       |                    |       |
| November 2007 |       | July 1 - September 30, 2007   |       | $                          | 0.57       |                    | $          | 64,798 |   |
| August 2007   |       | April 1 - June 30, 2007       |       | $                          | 0.57       |                    | 37,419     |   |
| May 2007      |       | January 1 - March 31, 2007    |       | $                          | 0.52       |                    | 30,001     |   |
| February 2007 |       | October 1 - December 31, 2006 |       | $                          | 0.52       |                    | 22,745     |   |
|               |       | Total 2007                              |       |                       |       | $                       | 154,963    |   |
|               |       |                                    |       |                       |       |                    |       |
| November 2006 |       | July 1 - September 30, 2006   |       | $                          | 0.43       |                    | $          | 12,197 |   |
| August 2006   |       | April 1 - June 30, 2006       |       | $                          | 0.40       |                    | 11,033     |   |
| May 2006      |       | January 13 - March 31, 2006   |       | $                          | 0.32       |                    | 8,826      |   |
|               |       | Total 2006                              |       |                       |       | $                       | 32,056     |   |

 

In January 2008, the Company’s Board of Directorsdeclared a cash distribution of $0.63 per unit with respect to the fourthquarter of 2007.  The distribution totaled approximately$72.2 million and was paid on February 14, 2008 to unitholders ofrecord as of the close of business on February 8, 2008.  This distribution represents a 10.5% increasein the Company’s annualized cash distribution rate, to $2.52 per unit, from$2.28 per unit for the third quarter of 2007.

 

69

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**LINNENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****- Continued**

 

***Cancellationof Units***

 

In January 2007, the Company purchased 226,561 restricted unitsfrom an employee for $7.4 million (market price on the day of purchase) inconjunction with the vesting of restricted unit awards.  The proceeds were used to fund the employee’spayroll taxes on the award, and the Company cancelled the units.

 

***Issuanceof Units***

 

In October 2007, the Company issued 77,381 units in connection withthe acquisition of royalty interests in certain oil and gas properties.

 

Subsequent to December 31, 2007, in January 2008, the Companyissued 600,000 units in connection with the acquisition of certain gasproperties in the Appalachian Basin (see Note 2).

 

***Initial Public Offering***

 

In 2006, the Company completed its IPO of 12,450,000 units representinglimited liability interest in the Company at $21.00 per unit, for net proceeds,after underwriting discounts of $18.3 million and offering expenses of $4.3million, of $238.8 million, of which $122.0 million was used to reduceindebtedness and $114.4 million was used to redeem a portion of membershipinterests in the Company and units held by certain holders and approximately$2.0 million was used to pay bonuses to certain executive officers of theCompany.

 

**(5)****                                ****Business and CreditConcentrations**

 

***Cash***

 

The Company maintains its cash in bank deposit accounts, which, attimes, may exceed federally insured amounts. The Company has not experienced any losses in such accounts.  The Company believes it is not exposed to anysignificant credit risk on its cash.

 

***Revenue and Trade Receivables***

 

The Company has aconcentration of customers who are engaged in oil and gas purchasing,transportation and/or refining within the United States.  This concentration of customers may impactthe Company’s overall exposure to credit risk, either positively or negatively,in that the customers may be similarly affected by changes in economic or otherconditions.  The Company’s customersconsist primarily of major oil and gas purchasers and the Company generallydoes not require collateral, since it has not experienced credit losses on suchsales.  The Company routinely assessesthe recoverability of all material trade and other receivables to determinecollectibility and accrues an allowance when, based on management’s judgment,it is probable that a receivable will not be collected and the amount can bereasonably estimated.  The balance in theCompany’s allowance for doubtful accounts was $100,000 at December 31,2007 and 2006.

 

For the year ended December 31, 2007, the Company’s three largestcustomers represented 19%, 18% and 15% of the Company’s sales.  For the year ended December 31, 2006,the Company’s two largest customers represented 54% and 17% of the Company’ssales.  The Company’s three largestcustomers represented approximately 48%, 14%, and 10% of the Company’s salesfor the year ended December 31, 2005.

 

At December 31, 2007, three customers’ trade accounts receivablefrom oil, gas and NGL sales accounted for more than 10% of the Company’s totaltrade accounts receivable.  As of December 31,2007, trade accounts receivable from the Company’s three largest customersrepresented approximately 22%, 13% and 12% of the Company’s receivables.  At December 31, 2006, three customers’trade accounts receivable from oil and gas sales accounted for more than 10% ofthe Company’s total trade accounts receivable. As 

 

70

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**LINNENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****- Continued**

 

of December 31, 2006, trade accounts receivable from the Company’sthree largest customers represented approximately 41%, 22% and 16% of theCompany’s receivables.

 

**(6)****                                ****Unit-Based Compensationand Other Benefit Plans**

 

***Incentive Plan Summary***

 

The Linn Energy, LLC Long-Term Incentive Plan (the “Plan”) becameeffective in December 2005.  ThePlan, which is administered by the Compensation Committee of the Board ofDirectors, permits the granting of unit grants, unit options, restricted units,phantom units and unit appreciation rights to employees, consultants andnon-employee directors under the terms of the Plan.  The unit options and restricted units vestratably over one to three years from the grant date of the award, unless othercontractual arrangements are made.  Thecontractual life of unit options is ten years. Unit awards were issued for the first time in January 2006, inconjunction with the Company’s IPO.

 

The Plan limits the number of units that may be delivered pursuant toawards to 3.9 million units, provided that no more than 1.5 million units maybe issued as restricted units.  The Boardof Directors and the Compensation Committee of the Board of Directors have theright to alter or amend the Plan or any part of the Plan from time to time,including increasing the number of units that may be granted, subject tounitholder approval as required by the exchange upon which the units are listedat that time.  However, no change in anyoutstanding grant may be made that would materially reduce the benefits to theparticipant without the consent of the participant.

 

Upon exercise or vesting of an award of, or settled in, units, theCompany will issue new units, acquire units on the open market or directly fromany person or use any combination of the foregoing, at the CompensationCommittee’s discretion.  If the Companyissues new units upon exercise or vesting of an award of, or settled in, units,the total number of units outstanding will increase.  To date, the Company has issued awards ofunit grants, unit options, restricted units and phantom units.  The Plan provides for all of the followingtypes of awards:

 

*Unit Grants*  A unit grantis a unit that vests immediately upon issuance.

 

*Unit Options*  A unit optionis a right to purchase a unit at a specified price at terms determined by theCompensation Committee.  Unit optionswill have an exercise price that will not be less than the fair market value ofthe units on the date of grant, and in general, will become exercisable over avesting period but may accelerate upon the achievement of specified financialobjectives, or upon a change in control of the Company.  If a grantee’s employment or relationshipterminates for any reason, the grantee’s unvested unit options will beautomatically forfeited unless the option agreement or the CompensationCommittee provides otherwise.

 

*Restricted Units*  A restrictedunit is a unit that vests over a period of time and that during such time issubject to forfeiture, and may contain such terms as the Compensation Committeeshall determine, including the period over which restricted units (and distributionsrelated to such units) will vest.  TheCompany intends the restricted units under the plan to serve as a means ofincentive compensation for performance and not primarily as an opportunity toparticipate in the equity appreciation of its units.  Therefore, plan participants will not pay anyconsideration for the restricted units they receive.  If a grantee’s employment, consultingrelationship or membership on the Board of Directors terminates for any reason,the grantee’s unvested restricted units will be automatically forfeited unlessthe Compensation Committee or the terms of the award agreement provideotherwise.

 

*Phantom Units/Unit Appreciation Rights* These awards may be settled in units, cash or a combinationthereof.  Such grants will contain termsas determined by the Compensation Committee, including the period or terms overwhich phantom units will vest.  If agrantee’s employment or service relationship terminates for any reason, thegrantee’s phantom units or unit appreciation rights will be automaticallyforfeited unless, and to the extent, the Compensation 

 

71

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**LINNENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****- Continued**

 

Committee or the terms of the award agreement provide otherwise.  While phantom units require no payment fromthe grantee, unit appreciation rights will have an exercise price that will notbe less than the fair market value of the units on the date of grant.  At December 31, 2007, the Company had21,000 phantom units issued and outstanding. To date, the Company has not issued unit appreciation rights.

 

***Securities Authorized forIssuance Under the Plan***

 

As of December 31, 2007, approximately 1,077,021 units wereissuable under the Plan pursuant to outstanding award or other agreements andan additional 916,572 units were reserved for future issuance under the Plan.

 

***Accounting for Unit-BasedCompensation***

 

The Company recognizes as expense, beginning at the grant date, thefair value of unit options and other equity-based compensation issued toemployees and non-employee directors. The value of the portion of the award that is ultimately expected tovest is recognized as expense over the requisite service period using the straight-linemethod in the Company’s consolidated statements of operations.

 

For the years ended, December 31, 2007 and 2006, the Companyrecorded unit-based compensation expense of approximately $12.5 million and$21.6 million, respectively, as a charge against income before income taxes,included in general and administrative expense on the consolidated statement ofoperations.  No related income taxbenefit was recognized due to non-deductibility and recognition of a valuationallowance for resulting net operating losses.

 

***Restricted/Unrestricted Units***

 

The fair value of unrestricted unit grants and restricted units issuedis determined based on the fair market value of the Company units on the dateof grant.  This value is amortized overthe vesting period, which varied from one month to three years from the date ofgrant.  A summary of the status of thenon-vested units as of December 31, 2007, is presented below:

 
| ** **                                 | ** ** | **Number of  Non-vested  Units** | ** ** | **Weighted  Average  Grant Date  Fair Value** | ** ** |
|--------------------------------------------|------------|----------------------------------|------------|-----------------------------------------------|------------|
|                                       |       |                             |       |                                          |       |
| Non-vested units at December 31, 2006 |       | 1,124,690                        |       | $                                             | 23.19      |   |
| Granted                                    |       | 577,700                          |       | $                                             | 31.16      |   |
| Vested                                     |       | (863,570                         | )          | $                                             | 22.44      |   |
| Forfeited                                  |       | (5,000                           | )          | $                                             | 32.35      |   |
| Non-vested units at December 31, 2007 |       | 833,820                          |       | $                                             | 29.43      |   |

 

The weighted-average grant-date fair value of unrestricted unit grantsand restricted units granted during 2006 was $22.98.

 

As of December 31, 2007, there was approximately $14.4 million ofunrecognized compensation cost related to non-vested restricted units.  The cost is expected to be recognized over aweighted average period of approximately 1.4 years.  The total fair value of units that vestedduring the period was approximately $19.4 million and $2.4 million for theyears ended December 31, 2007 and 2006, respectively.  The aggregate intrinsic value of vested unitsas of December 31, 2007 was approximately $24.5 million.

 

72

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**LINNENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****- Continued**

 

***Changes in Unit Options and UnitOptions Outstanding***

 

The following provides information related to unitoption activity for the year ended December 31, 2007:

 
| ** **                            | ** ** | **Number of  Units  Underlying  Options** | ** ** | **Weighted  Average  Exercise Price  Per Unit** | ** ** | **Weighted  Average  Grant Date  Fair Value** | ** ** | **Weighted  Average  Remaining  Contractual  Life in Years** | ** ** |
|---------------------------------------|------------|-------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|--------------------------------------------------------------|------------|
|                                  |       |                                      |       |                                            |       |                                          |       |                                                         |       |
| Outstanding at December 31, 2006 |       | 930,500                                   |       | $                                               | 24.24      |                                          | $          | 3.68                                                         |       |   |   |
| Granted                               |       | 93,000                                    |       | $                                               | 29.07      |                                          | $          | 4.59                                                         |       |   |   |
| Exercised                             |       | (14,562                                   | )          | $                                               | 23.81      |                                          | $          | 5.71                                                         |       |   |   |
| Forfeited                             |       | (11,917                                   | )          | $                                               | 25.11      |                                          | $          | 4.79                                                         |       |   |   |
| Outstanding at December 31, 2007 |       | 997,021                                   |       | $                                               | 24.68      |                                          | $          | 4.67                                                         |       | 8.62 |   |
| Exercisable at December 31, 2007 |       | 327,564                                   |       | $                                               | 23.92      |                                          | $          | 4.63                                                         |       | 8.48 |   |

 

The weighted-average grant-date fair value of options granted during2006 was $3.59.  The total intrinsicvalue of options exercised during 2007 was $95,000.  No options were exercised during 2006.

 

As of December 31, 2007, there was approximately $2.3 million oftotal unrecognized compensation cost related to non-vested unit options.  The cost is expected to be recognized over aweighted average period of approximately 1.4 years.  In addition, the exercisable unit options at December 31,2007 have an aggregate intrinsic value of approximately $0.8 million and alloutstanding unit options have an aggregate intrinsic value of approximately$2.2 million.  The total fair value ofall options that vested was approximately $1.5 million and $76,000 for theyears ended December 31, 2007 and 2006, respectively.  No options expired during the years ended December 31,2007 or 2006.

 

The fair value of unit-based compensation for unit options wasestimated on the date of grant using a Black-Scholes pricing model based oncertain assumptions.  The Company’sdetermination of the fair value of unit-based payment awards is affected by theCompany’s unit price as well as assumptions regarding a number of complex andsubjective variables.  The Company’semployee unit options have various restrictions including vesting provisionsand restrictions on transfers and hedging, among others, and often are expectedto be exercised prior to their contractual maturity.

 

Expected volatilities used in the estimation of fair value have beendetermined using available volatility data for the Company as well as anaverage of volatility computations of other identified peer companies in theoil and gas industry.  Expecteddistributions are estimated based on the Company’s distribution rate at thedate of grant.  Historical data of theCompany and other identified peer companies is used to estimate expected termbecause, due to the limited period of time its equity units have been publiclytraded, the Company does not have sufficient historical exercise data tocompute a reasonable estimation. Forfeitures are estimated using historical Company data and are revised,if necessary, in subsequent periods if actual forfeitures differ fromestimates.  All employees granted awardshave been determined to have similar behaviors for purposes of determining theexpected term used to estimate fair value. The risk-free rate for periods within the expected term of the unitoption is based on the U.S. Treasury yield curve in effect at the time ofgrant.  The fair values of the unitoption grants were based upon the following assumptions:

 
| ** **             | ** ** | **2007**        | ** ** | **2006**        | ** ** |
|------------------------|------------|-----------------|------------|-----------------|------------|
|                   |       |            |       |            |       |   |   |   |   |   |   |   |   |
| Expected volatility    |       | 30.40% - 35.58% |       | 29.70% - 31.30% |       |
| Expected distributions |       | 6.51% - 10.67%  |       | 7.20% - 8.50%   |       |
| Risk free rate         |       | 3.53% - 5.18%   |       | 4.31% - 5.04%   |       |
| Expected term          |       | 5.0 years       |       | 5.0 years       |       |
|                        |            |                 |            |                 |            |  |  |  |  |  |  |  |  |

 

73

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**LINNENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****- Continued**

 

Although the fair value of unit option grants is determined inaccordance with SFAS 123R using a Black-Scholes option-pricing model, thatvalue may not be indicative of the fair value observed in a willingbuyer/willing seller market transaction.

 

***Non-Employee Grants***

 

In February 2007, the Company granted an aggregate 150,000 unitwarrants to certain individuals in connection with an acquisition transitionservices agreement.  The unit warrantshave an exercise price of $25.50 per unit warrant, are fully exercisable at December 31,2007, and expire ten years from issuance. In accordance with SFAS 123R, the Company computed the fair valueof the unit warrants using the Black-Scholes model.  At December 31, 2007, the aggregate fairvalue of the unit warrants was approximately $1.4 million and the expense wasrecognized over the five-month term of the agreement through June 30,2007.  For the year ended December 31,2007, the Company recorded this amount in general and administrative expenseson the consolidated statement of operations.

 

***Defined Contribution Plan***

 

The Company sponsors a 401(k) defined contribution plan foreligible employees.  Companycontributions to the 401(k) plan consist of a discretionary matchingcontribution equal to 100% of the first 4% of eligible compensation contributedby the employee on a before-tax basis. The Company contributed approximately $0.8 million, $0.2 million and$0.1 million during the years ended December 31, 2007, 2006 and 2005,respectively, to the 401(k) plan’s trustee account.  The 401(k) plan funds are held in atrustee account on behalf of the plan participants.

 

**(7)****                                ****Debt**

 

***Credit Facility***

 

At December 31, 2007, the Company had a $1.8billion Third Amendedand Restated Credit Agreement (“CreditFacility”) with a maturity of August 2010. On January 31, 2008, the Credit Facility was amended toincrease the amount available for borrowing to $1.9 billion, all of which isconforming, effective until April 1, 2008, at which point the borrowingbase will be redetermined in accordance with the terms of the Credit Facility.

 

The borrowing base under the Credit Facility will be redeterminedsemi-annually by the lenders in their sole discretion, based on, among otherthings, reserve reports as prepared by reserve engineers taking into accountthe oil and gas prices at such time.  TheCompany’s obligations under the Credit Facility are secured by mortgages on itsoil and gas properties as well as a pledge of all ownership interests in itsoperating subsidiaries.  The Company isrequired to maintain the mortgages on properties representing at least 80% ofits oil and gas properties. Additionally, the obligations under the Credit Facility are guaranteedby all of the Company’s operating subsidiaries and may be guaranteed by anyfuture subsidiaries.

 

At the Company’s election, interest on borrowings under the CreditFacility is determined by reference to either LIBOR plus an applicable marginbetween 1.00% and 2.25% per annum or the alternate base rate (“ABR”) plus anapplicable margin between 0% and 0.75% per annum.  Interest is generally payable quarterly forABR loans and at the applicable maturity date for LIBOR loans.

 

The Credit Facility contains various covenants that limit the Company’sability to incur indebtedness, enter into interest rate swaps, grant certain liens,make certain loans, acquisitions, capital expenditures and investments, makedistributions other than from available cash, merge or consolidate, or engagein certain asset dispositions, including a sale of all or substantially all ofits assets.  The Credit Facility alsocontains covenants that require the Company to maintain Adjusted EBITDA tointerest expense and current liquidity financial ratios.  The Company is in compliance with allfinancial and other covenants of its Credit Facility.

 

74

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**LINNENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****- Continued**

 

As of December 31, 2007 and 2006, the CreditFacility consisted of the following:

 
| ** **              | ** ** | **December 31,** | ** ** |
|-------------------------|------------|-----------------------|------------|
| ** **              | ** ** | **2007**              | ** ** | **2006** | ** ** |
| ** **              | ** ** | **(in thousands)**    | ** ** |
|                    |       |                  |       |   |   |
| Total (1)               |       | $                     | 1,443,000  |   | $ | 425,750 |   |
| Less current maturities |       | —                |       | — |   |
|                    |       | $                     | 1,443,000  |   | $ | 425,750 |   |

----

(1)   Variable rate of 7.02% and 7.125% at December 31,2007 and 2006, respectively

 

At December 31, 2007, the Company also had $2.5 millionoutstanding letters of credit, which reduce its borrowing availability underthe Credit Facility.  At December 31,2007, available borrowing under Credit Facility was $354.5 million.

 

***Subordinated Bridge Loan***

 

In August 2006, in order to fund a portion of the acquisitions ofoil and gas properties (see Note 2), the Company entered into a $250.0million subordinated bridge loan. Interest was determined by reference to LIBOR plus an applicable marginof 4.00% per annum; or a domestic bank rate plus an applicable margin of 2.50%per annum.  In October 2006, thesubordinated bridge loan was repaid in full with proceeds from the Company’sprivate placement of units (see Note 4).

 

***Term Loan***

 

On January 31, 2008, in order to fund a portion of the January 2008acquisition of oil and gas properties in the Mid-Continent (see Note 2),the Company entered into a $400.0 million Second Lien Term Loan Agreement witha maturity of July 31, 2009 (“Term Loan”). In connection with the Term Loan, the Company paid financing fees ofapproximately $6.0 million, which were deferred and amortized over the life ofthe Term Loan.  The Company’s obligationsunder the Term Loan are secured by a second priority lien on all oil and gasproperties as well as a second priority pledge on all ownership interests inits operating subsidiaries.  The Company’sobligations under the Term Loan are guaranteed by all the Company’s operatingsubsidiaries and may be guaranteed by any future subsidiaries.  Covenants under the Term Loan aresubstantially similar to those under the Credit Facility. Interest isdetermined by reference to LIBOR plus an applicable margin of 5.0% for thefirst twelve months and 7.5% for the remaining period until maturity or adomestic bank rate plus an applicable margin of 3.5% for the first twelvemonths and 6.0% for the remaining period until maturity.

 

***Other******Notes Payable***

 

The Company has notes payable for a building, vehicles and equipment,which are secured by the respective asset and expire at various dates from 2008through 2024.  At December 31, 2007and 2006, the balance in notes payable included in other noncurrent liabilitieson the consolidated balance sheets was $0.8 million and $2.5 million,respectively.  The current portionincluded in other current liabilities on the consolidated balance sheets was$0.7 million and $0.9 million, respectively. At December 31, 2007 and 2006, notes payable includes approximately$1.1 million and $1.0 million, respectively, of notes payable on which interestwas imputed at 7.0%.

 

**(8)****                                ****Interest Rate Swaps**

 

The Company has entered into interest rate swapagreements based on LIBOR to minimize the effect of fluctuations in interestrates.  If LIBOR is lower than the fixedrate in the contract, the Company is required to pay the counterparties thedifference, and conversely, the counterparties are required to pay the Companyif LIBOR is higher than the fixed rate in the contract.  The Company did not designate the interestrate swap 

 

75

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**LINNENERGY, LLC****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****- Continued**

 

agreements as cash flow hedges underSFAS 133; therefore, the changes in fair value of these instruments arerecorded in current earnings.

 

The following summarizes theCompany’s interest rate swaps outstanding:

 
| ** **        | ** ** | **December 31,** | ** ** |
|-------------------|------------|-----------------------|------------|
| ** **        | ** ** | **2007**              | ** ** | **2006** | ** ** |
| ** **        | ** ** | **(in thousands)**    | ** ** |
|              |       |                  |       |   |   |
| Total liabilities |       | $                     | 30,070     |   | $ | 423 |   |
| Less total assets |       | (142                  | )          | (44 | ) |
|              |       | $                     | 29,928     |   | $ | 379 |   |

 

Unrealized gains (losses) due to the change in thefair value of approximately $(29.5) million, $82,000 and $1.0 million for the years ended December 31, 2007,2006 and 2005, respectively, are recorded ingain (loss) on interest rate swaps in the consolidated statements ofoperations.

 

Realized gains (losses) of approximately $1.5million, $0.3 million and $17,000 for the years ended December 31, 2007, 2006 and 2005,respectively, are recorded in gain (loss) oninterest rate swaps in the consolidated statements of operations.

 

The following presents theoutstanding notional amounts and maximum number of months outstanding ofinterest rate swaps:

 
| ** **                           | ** ** | **December 31,**             | ** ** |
|--------------------------------------|------------|-----------------------------------|------------|
| ** **                           | ** ** | **2007**                          | ** ** | **2006** | ** ** |
| ** **                           | ** ** | **(in thousands, except months)** | ** ** |
|                                 |       |                              |       |   |   |
| Notional amount                      |       | $                                 | 1,212,000  |   | $ | 50,000 |   |
| Maximum number of months outstanding |       | 36                                |       | 24 |   |
|                                      |            |                                   |            |  |  |  |  |

 

The following presents thesettlement terms of the interest rate swaps:

 
| ** **                                                 | ** ** | **Notional  Amount** | ** ** | **Fixed  Rate** | ** ** |
|------------------------------------------------------------|------------|----------------------|------------|-----------------|------------|
| ** **                                                 | ** ** | **(in thousands)**   | ** ** | ** **      | ** ** |
| ** **                                                 | ** ** | ** **           | ** ** | ** **      | ** ** |
| Settles monthly, October 2007 -  January 2008    |       | $                    | 985,000    |            | 4.79       | % |
| Settles monthly,  January 2008 - January 2009    |       | $                    | 177,000    |            | 3.50       | % |
| Settles monthly,  January 2008 - January 2009    |       | $                    | 985,000    |            | 4.25       | % |
| Settles monthly,  January 2009 - January 2010    |       | $                    | 227,000    |            | 4.89       | % |
| Settles monthly,  January 2009 - January 2011    |       | $                    | 985,000    |            | 5.10       | % |
| Settles quarterly,  January 2008 - December 2008 |       | $                    | 50,000     |            | 5.79       | % |

 

**(9)****                                ****Commodity Derivatives**

 

The Company sells oil, gas and NGL in the normalcourse of its business and utilizes derivative instruments to minimize thevariability in cash flows due to price movements in oil, gas and NGL.  The Company enters into derivativeinstruments such as swap contracts and put options to hedge a portion of itsforecasted oil, gas and NGL sales.  Oilderivatives are used to hedge oil and NGL sales.

 

76

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**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

The following table summarizes open positions asof December 31, 2007 and represents, as of such date, derivatives in placethrough December 31, 2013, on annual production volumes.

 
| ** **                            | ** ** | **Year  2008** | ** ** | **Year  2009** | ** ** | **Year  2010** | ** ** | **Year  2011** | ** ** | **Year  2012** | ** ** | **Year  2013** | ** ** |
|---------------------------------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|----------------|------------|
| **Gas Positions:**                    |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Fixed Price Swaps:                    |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMMBtu)               |       | 45,247         |       | 49,271         |       | 42,086         |       | 38,741         |       | 34,066         |       | —         |       |
| Average Price  ($/MMBtu)              |       | $              | 8.48       |           | $          | 8.32           |       | $              | 8.14       |           | $          | 8.08           |       | $ | 8.45 |   | $ | — |   |
| Puts:                                 |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMMBtu)               |       | 6,463          |       | 6,960          |       | 6,960          |       | 6,960          |       | —         |       | —         |       |
| Average Price ($/MMBtu)               |       | $              | 8.07       |           | $          | 7.50           |       | $              | 7.50       |           | $          | 7.50           |       | $ | — |   | $ | — |   |
| PEPL Puts:  (1)                       |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMMBtu)               |       | 3,854          |       | 5,334          |       | 10,634         |       | 13,259         |       | 5,934          |       | —         |       |
| Average Price  ($/MMBtu)              |       | $              | 7.85       |           | $          | 7.85           |       | $              | 7.85       |           | $          | 7.85           |       | $ | 7.85 |   | $ | — |   |
| Total:                                |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMMBtu)               |       | 55,564         |       | 61,565         |       | 59,680         |       | 58,960         |       | 40,000         |       | —         |       |
| Average Price  ($/MMBtu)              |       | $              | 8.39       |           | $          | 8.19           |       | $              | 8.02       |           | $          | 7.96           |       | $ | 8.36 |   | $ | — |   |
|                                  |       |           |       |           |       |           |       |           |       |           |       |           |       |
| **Oil Positions:**                    |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Fixed Price Swaps:                    |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MBbls)                |       | 1,413          |       | 1,587          |       | 1,300          |       | 1,223          |       | 1,175          |       | 900            |       |
| Average Price  ($/Bbl)                |       | $              | 73.00      |           | $          | 72.89          |       | $              | 73.87      |           | $          | 75.99          |       | $ | 72.41 |   | $ | 72.22 |   |
| Puts: (2)                             |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MBbls)                |       | 1,671          |       | 1,843          |       | 2,250          |       | 2,352          |       | 500            |       | —         |       |
| Average Price ($/Bbl)                 |       | $              | 72.86      |           | $          | 72.13          |       | $              | 70.56      |           | $          | 69.11          |       | $ | 77.73 |   | $ | — |   |
| Total:                                |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MBbls)                |       | 3,084          |       | 3,430          |       | 3,550          |       | 3,575          |       | 1,675          |       | 900            |       |
| Average Price  ($/Bbl)                |       | $              | 72.92      |           | $          | 72.48          |       | $              | 71.77      |           | $          | 71.46          |       | $ | 74.00 |   | $ | 72.22 |   |
|                                  |       |           |       |           |       |           |       |           |       |           |       |           |       |
| **Gas Basis Differential Positions:** |       |           |       |           |       |           |       |           |       |           |       |           |       |
| PEPL Basis Swaps: (3)                 |       |           |       |           |       |           |       |           |       |           |       |           |       |
| Hedged Volume  (MMMBtu)               |       | 36,146         |       | 34,666         |       | 29,366         |       | 26,741         |       | 34,066         |       | —         |       |
| Hedged  Differential ($/MMBtu)        |       | $              | (0.95      | )              | $          | (0.95          | )          | $              | (0.95      | )              | $          | (0.95          | )          | $ | (0.95 | ) | $ | — |   |

----

(1)                  Settle on the PEPL spot price of gas tohedge basis differential associated with gas production in the Mid-Continentregion.

 

(2)                  The Company utilizes oil puts to hedgerevenues associated with its NGL production.

 

(3)                  Represents a swap of the basis betweenNYMEX and the PEPL spot price of gas of $(0.95) per MMBtu for the volumeshedged.

 

The following presents the outstanding notional amounts and maximumnumber of months outstanding of oil and gas derivatives:

 
| ** **                                          | ** ** | **December 31,** | ** ** |
|-----------------------------------------------------|------------|-----------------------|------------|
| ** **                                          | ** ** | **2007**              | ** ** | **2006** | ** ** |
| ** **                                          | ** ** | ** **            | ** ** | ** ** | ** ** |
| Outstanding notional amounts of gas hedges (MMMBtu) |       | 275,769               |       | 31,503 |   |
| Maximum number of months gas hedges outstanding     |       | 59                    |       | 35 |   |
| Outstanding notional amounts of oil hedges (MBbls)  |       | 16,214                |       | 8,700 |   |
| Maximum number of months oil hedges outstanding     |       | 72                    |       | 60 |   |

 

77

----

 

**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

** **

Settled derivatives on gas production for theyear ended December 31, 2007 included a volume of 25,933 MMMBtu at anaverage contract price of $8.44.  Settled derivatives on oil and NGL production forthe year ended December 31, 2007 includeda volume of 1,952 MBbls at an average contract price of $69.09.  The gas derivatives are settled based on theclosing NYMEX future price of gas or on the published PEPL spot price of gas onthe settlement date, which occurs on the third day preceding the productionmonth.  The oil transactions are settledbased on the average month’s daily NYMEX price of light oil and settlementoccurs on the final day of the production month.

 

Realized gains (losses) of approximately $43.2million, $25.5 million and $(51.4) million for the years endedDecember 31, 2007, 2006 and 2005, respectively, are recorded in gain (loss) on oil and gas derivatives in the consolidatedstatements of operations.

 

By using derivative instruments to hedge exposures tochanges in commodity prices, the Company exposes itself to credit risk andmarket risk.  Credit risk is the failureof the counterparty to perform under the terms of the derivative contract.  When the fair value of a derivative contractis positive, the counterparty owes the Company, which creates credit risk.  The Company minimizes the credit risk inderivative instruments by entering into transactions with credit-worthy counterparties.

 

Subsequent to December 31, 2007 the Companyentered into additional hedging contracts (see Note 12).

 

**(10)****                          Propertyand Equipment**

** **

Property and equipmentconsists of the following:

 

| ** **                           | ** ** | **December 31,** | ** ** |
|--------------------------------------|------------|-----------------------|------------|
| ** **                           | ** ** | **2007**              | ** ** | **2006** | ** ** |
| ** **                           | ** ** | **(in thousands)**    | ** ** |
|                                 |       |                  |       |   |   |
| Land                                 |       | $                     | 1,052      |   | $ | 308 |   |
| Buildings and leasehold improvements |       | 8,510                 |       | 2,759 |   |
| Vehicles                             |       | 7,405                 |       | 3,097 |   |
| Aircraft                             |       | —                |       | 5,890 |   |
| Drilling and other equipment         |       | 12,313                |       | 8,611 |   |
| Furniture and office equipment       |       | 8,127                 |       | 1,966 |   |
|                                 |       | 37,407                |       | 22,631 |   |
| Less accumulated depreciation        |       | (5,383                | )          | (1,877 | ) |
|                                 |       | $                     | 32,024     |   | $ | 20,754 |   |

 

Depreciation expense on the above assets for the years endedDecember 31, 2007, 2006 and 2005 was approximately $3.8 million, $1.4million and $0.9 million, respectively.

 

**(11)****                          AssetRetirement Obligations**

** **

Asset retirement obligations (“ARO”),associated with retiring tangible long-lived assets, are recognized as aliability in the period in which a legal obligation is incurred and becomesdeterminable.  This liability is offsetby a corresponding increase in the carrying amount of the underlyingasset.  The cost of the tangible asset,including the initially recognized ARO, is depleted such that the cost of theARO is recognized over the useful life of the asset.  The ARO is recorded at fair value, andaccretion expense is recognized over time as the discounted liability isaccreted to its expected settlement value. The fair value of ARO is measured using expected future cash outflowsdiscounted at the Company’s credit-adjusted risk-free interest rate (7.0%, 7.0%and 5.8% for the years ended December 31, 2007, 2006 and 2005, respectively).

 

Inherent in the fair value calculation ofARO are numerous assumptions and judgments including the ultimate settlementamounts, inflation factors, credit adjusted discount rates, timing ofsettlement, and

 

78

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** **

**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

 

changes in legal, regulatory,environmental and political environments. To the extent future revisions to these assumptions impact the fairvalue of the existing ARO liability, a corresponding adjustment is made to theasset balance.

 

The followingpresents a reconciliation of the ARO liability:

 

| ** **                                              | ** ** | **December 31,** | ** ** |
|---------------------------------------------------------|------------|-----------------------|------------|
| ** **                                              | ** ** | **2007**              | ** ** | **2006** | ** ** |
| ** **                                              | ** ** | **(in thousands)**    | ** ** |
|                                                    |       |                  |       |   |   |
| ARO at beginning of year                                |       | $                     | 8,594      |   | $ | 5,443 |   |
| Liabilities added related to acquisitions and  drilling |       | 15,922                |       | 2,837 |   |
| Current year accretion expense                          |       | 1,014                 |       | 314 |   |
| Revision of estimates                                   |       | 3,543                 |       | — |   |
| ARO at end of year                                      |       | $                     | 29,073     |   | $ | 8,594 |   |

 

**(12)****                          Commitmentsand Contingencies**

 

The Company would have increased exposure to oil, gasand NGL price fluctuations on underlying sale contracts should thecounterparties to the Company’s derivative instruments or the counterparties tothe Company’s oil, gas and NGL marketing contracts not perform.  Such non-performance is not anticipated.  There were no counterparty default lossesduring the years ended December 31, 2007, 2006 or 2005.

 

From time to time the Company is a party to variouslegal proceedings or is subject to industry rulings that could bring rise toclaims in the ordinary course of business. The Company is not currently a party to any litigation or pending claimsthat it believes would have a material adverse effect on the Company’sbusiness, financial condition, results of operations or liquidity.

 

On December 31, 2007, the Company entered intohedging contracts to reduce oil price risk exposures related to its acquisitionfrom Lamamco (see Note 2).  Thecontracts cover approximately 229,000 Bbls of oil for 2008 and 250,000 Bbls peryear from 2009 through 2012.  Thecontracts included a deal-contingent option to enter into oil swaps uponconsummation of the acquisition for which the Company paid commitment fees andpremiums totaling approximately $1.3 million to the counterparty, LehmanBrothers Holding, Inc. (a related party to the Company, see Note 16) inJanuary 2008.  This amount is included inother noncurrent liabilities on the consolidated balance sheet at December 31,2007.  The Company’s commitment to enterinto the swaps was contingent on the closing of the acquisition.

 

**(13)****                          EarningsPer Unit**

 

Basic earnings per unit is computed inaccordance with SFAS No. 128, *“Earnings Per Share”*(“SFAS 128”) by dividing net earningsattributable to unitholders by the weighted average number of units outstandingduring each period.  Diluted earnings perunit is computed by adjusting the average number of units outstanding for thedilutive effect, if any, of unit equivalents. The Company uses the treasury stock method to determine the dilutiveeffect.  At December 31, 2006, theCompany had two classes of units outstanding: (i) unitsrepresenting limited liability company interests (“units”) listed on The NASDAQGlobal Market under the symbol “LINE” and (ii) Class B units.

 

In accordance with SFAS 128, dualpresentation of basic and diluted earnings per unit has been presented in theconsolidated statements of operations for the year ended December 31, 2006for each class of units issued and outstanding at that date, units andClass B units.  Net income per unitwas allocated to the units and the Class B units on an equal basis.  Certain existing holders of Linn Energy unitstotaling over 50% committed in advance to vote at a unitholder meeting in favorof the conversion of Class B units to units and the Class B unitswere converted to units on a one-for-one basis in January 2007; therefore, theClass B units share equally with the units in the net income of theCompany.  Since the Class B unitswere converted to units in January

 

79

----

** **

**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

 

2007, they share equally in the February 2007distributions and all future distributions. The Company made no distributions to Class B unitholders during theperiod the Class B units were outstanding.

 

For the periods prior to the Company’s IPO, equivalent units werecalculated by adjusting pre-IPO members’ membership interests by the exchangeratio to reflect the exchange of pre-IPO membership interests for post-IPOunits and cash immediately prior to completion of the IPO (see Note 4).

 

The following reconciliation presents the impact onthe unit amounts of potential common units and the earnings per unit amounts:

 

| ** **                                       | ** ** | **Year Ended December 31,**            | ** ** |
|--------------------------------------------------|------------|---------------------------------------------|------------|
| ** **                                       | ** ** | **2007**                                    | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                       | ** ** | **(in thousands, except per unit amounts)** | ** ** |
|                                             |       |                                        |       |   |   |   |   |
| Net income  (loss)                               |       | $                                           | (364,349   | ) | $ | 79,185 |   | $ | (56,351 | ) |
| ** **                                       | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Weighted  average units outstanding:**         | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Basic units outstanding                          |       | 68,916                                      |       | 28,281 |   | 20,518 |   |
| Dilutive effect of unit equivalents (1)          |       | —                                      |       | 2,104 |   | — |   |
| Diluted units outstanding                        |       | 68,916                                      |       | 30,385 |   | 20,518 |   |
|                                             |       |                                        |       |   |   |   |   |
| **Weighted  average Class B units outstanding:** | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Basic Class B units outstanding                  |       | —                                      |       | 1,737 |   | — |   |
| Dilutive effect of unit equivalents              |       | —                                      |       | — |   | — |   |
| Diluted Class B units outstanding                |       | —                                      |       | 1,737 |   | — |   |
|                                             |       |                                        |       |   |   |   |   |
| **Net  income (loss) per unit:**                 | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** |
| Units – basic                               |       | $                                           | (5.29      | ) | $ | 2.64 |   | $ | (2.75 | ) |
| Units – diluted                             |       | $                                           | (5.29      | ) | $ | 2.61 |   | $ | (2.75 | ) |
|                                             |       |                                        |       |   |   |   |   |
| Class B units – basic                       |       | $                                           | —     |   | $ | 2.64 |   | $ | — |   |
| Class B units – diluted                     |       | $                                           | —     |   | $ | 2.61 |   | $ | — |   |

----

(1)              Excludes the effect of averageanti-dilutive common stock equivalents related to unit options and warrants andunvested restricted units of 434,821 and 234,016 for the years endedDecember 31, 2007 and 2006, respectively. All equivalent units were anti-dilutive for the year endedDecember 31, 2007 as the Company reported a net loss from operations.

 

**(14)****                          OperatingLeases**

** **

The Company leases office space and other property and equipment underlease agreements expiring on various dates through 2015.  The Company recognized expense underoperating leases of approximately $1.2 million, $0.5 million and $0.4 millionfor the years ended December 31, 2007, 2006 and 2005, respectively.

 

80

----

 

**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

 

As ofDecember 31, 2007, future minimum lease payments were as follows:

 

| ** ** | ** ** | **(in thousands)** | ** ** |
|------------|------------|--------------------|------------|
| ** ** | ** ** | ** **         | ** ** |
| 2008       |       | $                  | 2,752      |   |
| 2009       |       | 2,839              |       |
| 2010       |       | 2,857              |       |
| 2011       |       | 2,559              |       |
| 2012       |       | 2,374              |       |
| Thereafter |       | 2,566              |       |
|       |       | $                  | 15,947     |   |

** **

**(15)****                         ****Income Taxes**

** **

The Company is treated as a partnership forfederal and state income tax purposes. As such, it is not a taxable entity and does not directly pay federaland state income tax.  Its taxable incomeor loss, which may vary substantially from the net income or net loss reportedin the consolidated statements of operations, is includable in the federal andstate income tax returns of each unitholder. Accordingly, no recognition has been given to federal and state incometaxes for the operations of the Company except as described below.  The aggregate difference in the basis of netassets for financial and tax reporting purposes cannot be readily determined asthe Company does not have access to information about each unitholder’s taxattributes in the Company.

 

Certain of the Company’ssubsidiaries are Subchapter C-corporations subject to corporate incometaxes.  The income tax provisionattributable to the Company’s taxable subsidiaries’ losses before income taxesconsisted of the following:

 

| ** **          | ** ** | **Year Ended December 31,** | ** ** |
|---------------------|------------|----------------------------------|------------|
| ** **          | ** ** | **2007**                         | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **          | ** ** | **(in thousands)**               | ** ** |
| **Current taxes:**  | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Federal             |       | $                                | (145       | ) | $ | — |   | $ | — |   |
| State               |       | (68                              | )          | (32 | ) | — |   |
| **Deferred taxes:** | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Federal             |       | (3,147                           | )          | 2,999 |   | (57 | ) |
| State               |       | (213                             | )          | 435 |   | (17 | ) |
| Total               |       | $                                | (3,573     | ) | $ | 3,402 |   | $ | (74 | ) |

 

As of December 31, 2007 and 2006, theCompany’s taxable entities had approximately $6.4 million and $10.1 million,respectively, of net operating loss carryforwards for federal income taxpurposes, which will begin expiring in 2025.

 

Income tax expense differedfrom amounts computed by applying the federal income tax rate of 35% to pre-taxincome as a result of the following:

 

| ** **                                    | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------|------------|----------------------------------|------------|
| ** **                                    | ** ** | **2007**                         | ** ** | **2006** | ** ** | **2005** | ** ** |
|                                          |       |                             |       |   |   |   |   |
| Federal statutory rate                        |       | 35.0                             | %          | (35.0 | )% | 34.0 | % |
| State, net of federal tax benefit             |       | (0.1                             | )          | 0.4 |   | –– |   |
| Income (loss) from non-taxable entities       |       | (35.1                            | )          | 50.6 |   | (34.0 | ) |
| Non-deductible compensation                   |       | (0.3                             | )          | (9.1 | ) | –– |   |
| Other items                                   |       | (0.4                             | )          | (2.3 | ) | (0.1 | ) |
| Income tax benefit (provision)/effective rate |       | (0.9                             | )%         | 4.6 | % | (0.1 | )% |

 

81

----

** **

**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

 

Significant components of the deferred tax assets and liabilities were asfollows:

 
| ** **                                                             | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                             | ** ** | **2007**              | ** ** | **2006** | ** ** |
| ** **                                                             | ** ** | **(in thousands)**    | ** ** |
| **Deferred tax assets:**                                               | ** ** | ** **            | ** ** | ** ** | ** ** |
| Net operating  loss carryforwards                                      |       | $                     | 2,449      |   | $ | 4,227 |   |
| Unit-based  compensation                                               |       | 3,762                 |       | 1,766 |   |
| Other                                                                  |       | 285                   |       | 358 |   |
| Valuation  allowance                                                   |       | (4,249                | )          | (2,318 | ) |
| Total deferred  tax assets                                             |       | 2,247                 |       | 4,033 |   |
|                                                                   |       |                  |       |   |   |
| **Deferred tax liabilities:**                                          | ** ** | ** **            | ** ** | ** ** | ** ** |
| Property and  equipment principally due to differences in depreciation |       | (2,247                | )          | (673 | ) |
| Total deferred  tax liabilities                                        |       | (2,247                | )          | (673 | ) |
| Net deferred tax  assets (liabilities)                                 |       | $                     | —     |   | $ | 3,360 |   |

 

Net deferred tax liabilities were classifiedin the consolidated balance sheets as follows:

 
| ** **                             | ** ** | **2007**           | ** ** | **2006**   | ** ** |
|----------------------------------------|------------|--------------------|------------|------------|------------|
| ** **                             | ** ** | **(in thousands)** | ** ** |
| ** **                             | ** ** | ** **         | ** ** | ** ** | ** ** |
| Deferred tax asset                     |       | $                  | 2,247      |       | $          | 4,033 |   |
| Deferred tax liability                 |       | (2,247             | )          | (673       | )          |
| Net deferred tax  assets (liabilities) |       | $                  | —     |       | $          | 3,360 |   |

 

In assessing the realizability of deferred tax assets, managementconsiders whether it is more likely than not that some portion or all of thedeferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon thegeneration of future taxable income during the periods in which those temporarydifferences become deductible. Management considers the scheduled reversal of deferred tax liabilities,projected future taxable income and tax planning strategies in making thisassessment.  Based upon the level ofhistorical taxable income and projections for future taxable income over theperiods in which the deferred tax assets are deductible, management believes itis not more likely than not that the Company will realize the benefits of thesedeductible differences at December 31, 2007; therefore, the Company hasrecorded a valuation allowance against the deferred tax asset.

 

TheCompany adopted Financial Interpretation No. 48, *“Accountingfor Uncertainty in Income Taxes – an interpretation of FASB StatementNo. 109”* (“FIN 48”) on January 1, 2007.  FIN 48 requires that the Companyrecognize only the impact of income tax positions that, based on their merits,are more likely than not to be sustained upon audit by a taxing authority.  It also requires expanded financial statementdisclosure of such positions.

 

In evaluating its currenttax positions in order to identify any material uncertain tax positions, theCompany developed a policy in identifying uncertain tax positions that considerssupport for each tax position, industry standards, tax return disclosures andschedules and the significance of each position.  As of December 31, 2007, the Company hadno material uncertain tax positions.

 

82

----

 

**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

 

**(16)****                          RelatedParty Transactions**

** **

***Lehman Brothers Holding, Inc.***

 

AtDecember 31, 2007, on an aggregate basis, a group of certain direct orindirect wholly owned subsidiaries of Lehman Brothers Holding, Inc. (“Lehman”)owned over 10% of the Company’s outstanding units, acquired during 2006 and2007 in the Company’s private placements of units (see Note 4).  As such, Lehman is considered a related partyunder the provisions of SFAS No. 57 *“Related PartyDisclosures.”* Lehmansubsidiaries provide certain services to the Company, including participationin the Company’s Credit Facility (see Note 7) and sale of commodityderivative instruments (see Note 9), which were all consummated on termsequivalent to those that prevail in arm’s-length transactions.

 

In conjunctionwith its private placement of units, the Company received proceeds from Lehmanof approximately $378.7 million and $46.0 million during the years endedDecember 31, 2007 and 2006, respectively.

 

During the yearended December 31, 2007, the Company paid Lehman underwriting fees ofapproximately $13.5million.  In addition, during the years endedDecember 31, 2007 and 2006, the Company paid distributions on units toLehman of approximately $15.2 million and $0.4 million, respectively.  During the year ended December 31, 2007,the Company purchased approximately $226.3 million in oil and gas put and swapcontracts from Lehman.

 

During the yearended December 31, 2007, the Company paid Lehman, through theadministrator of its Credit Facility, interest on borrowings under its CreditFacility of approximately $1.3 million and financing fees of approximately $0.1million.  During the year endedDecember 31, 2006, the Company paid Lehman interest on borrowings underits Credit Facility of approximately $0.8 and financing fees of approximately$42,000.

 

The following setsforth the amounts due to or from Lehman as of the respective balance sheetdates included in the accompanying consolidated financial statements:

 

| ** **                                       | ** ** | **December 31,**   | ** ** |
|--------------------------------------------------|------------|--------------------|------------|
| ** **                                       | ** ** | **2007**           | ** ** | **2006** | ** ** |
| ** **                                       | ** ** | **(in thousands)** | ** ** |
| **Assets:**                                      | ** ** | ** **         | ** ** | ** ** | ** ** |
| Current oil and  gas derivative assets           |       | $                  | 14,226     |   | $ | 2,218 |   |
| Noncurrent oil  and gas derivative assets        |       | $                  | —     |   | $ | 3,538 |   |
| **Liabilities:**                                 | ** ** | ** **         | ** ** | ** ** | ** ** |
| Accrued interest  payable – Credit Facility |       | $                  | 162        |   | $ | 79 |   |
| Other current  liabilities                       |       | $                  | 1,278      |   | $ | — |   |
| Credit Facility                                  |       | $                  | 40,404     |   | $ | 15,966 |   |
| Noncurrent oil  and gas derivative liabilities   |       | $                  | 7,028      |   | $ | — |   |

*** ***

***Other***

*** ***

Eric P. Linn,brother of the Company’s Chairman and Chief Executive Officer, serves asPresident of a wholly owned subsidiary of the Company.  Mr. Linn was paid a base salary of $0.2million, $0.2 million and $0.1 million, during the years ended December 31,2007, 2006 and 2005, respectively, which is included in operating expenses onthe consolidated statements of operations.

 

During 2007,Quantum Energy Partners sold all Linn Energy units previously held and is nolonger considered a related party to the Company.

 

83

----

** **

**LINN ENERGY, LLCNOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued**

 

During the year ended December 31, 2007, the Companymade payments of approximately $0.2 million to a company owned by a member ofits Board of Directors.  The paymentsreflect purchases of gas and are included in natural gas marketing expenses onthe consolidated statement of operations. The expenses were consummated on terms equivalent to those that prevailin arm’s-length transactions.

 

During the yearended December 31, 2006, the Company made payments of approximately $0.4million to a company owned by one of its senior executives.  The payments reflect reimbursement formaintenance and hourly usage fees for business use of an aircraft that waspartially owned by the senior executive. These costs are included in general and administrative expense on theconsolidated statement of operations. The fees and expenses associated with the reimbursements wereconsummated on terms equivalent to those that prevail in arm’s-lengthtransactions.  In the third quarter of2006, the Company purchased an ownership interest in an airplane for corporatetravel from a third party; therefore, these reimbursements will not beongoing.  Simultaneous with thistransaction, the senior executive was able to fully liquidate the investment inthe aircraft owned by his company.

 

**(17)         Supplemental Disclosures to theConsolidated Statements of Cash Flows**

 
| ** **                                                                                        | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                        | ** ** | **2007**                         | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                                                        | ** ** | **(in thousands)**               | ** ** |
| **Supplemental disclosure of cash flow  information:**                                            | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Cash payments  for interest                                                                       |       | $                                | 57,348     |   | $ | 24,147 |   | $ | 6,510 |   |
| **Supplemental disclosures of non-cash investing  activities:**                                   | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| In connection  with the purchase of oil and gas properties, liabilities were assumed as  follows: |       |                             |       |   |   |   |   |
| Fair value of  assets acquired                                                                    |       | $                                | 2,726,376  |   | $ | 472,499 |   | $ | 123,514 |   |
| Cash paid                                                                                         |       | (2,665,924                       | )          | (469,274 | ) | (122,065 | ) |
| Liabilities  assumed, net                                                                         |       | $                                | 60,452     |   | $ | 3,225 |   | $ | 1,449 |   |

 

 

84

----

 

** **

**LINN ENERGY, LLC**

**SUPPLEMENTAL OIL AND GAS DATA (Unaudited)**

** **

**(A)****                               CostsIncurred in Oil and Gas Property Acquisition, Exploration and DevelopmentActivities**

** **

Costs incurred in oil and gas property acquisition anddevelopment are presented below:

 

| ** **                          | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------|------------|----------------------------------|------------|
| ** **                          | ** ** | **2007**                         | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                          | ** ** | **(in thousands)**               | ** ** |
| Property acquisition costs: (1)     |       |                             |       |   |   |   |   |
| Proved                              |       | $                                | 2,422,983  |   | $ | 450,232 |   | $ | 118,489 |   |
| Unproved                            |       | 148,284                          |       | 4,062 |   | 579 |   |
| Development costs (2)               |       | 189,466                          |       | 47,112 |   | 27,145 |   |
| Gas compression plant and pipelines |       | 91,370                           |       | 15,232 |   | 4,043 |   |
| Total costs  incurred               |       | $                                | 2,852,103  |   | $ | 516,638 |   | $ | 150,256 |   |

----

(1)     Property acquisition costs include costs incurred to purchase,lease, or otherwise acquire a property (see Note 2).

 

(2)     Development costs include costs incurred to gain access to andprepare development well locations for drilling, to drill and equip developmentwells and to provide facilities to extract, treat and gather oil and gas.  Additionally, development costs include assetretirement costs of $3.9 million, $0.1 million and $0.3 million during theyears ended December 31, 2007, 2006 and 2005, respectively (see Note 11).

** **

**(B)****                               Oiland Gas Capitalized Costs**

** **

Aggregate capitalized costs related to oil and gas productionactivities with applicable accumulated depreciation, depletion and amortizationare presented below:

 

| ** **                                                 | ** ** | **December 31,** | ** ** |
|------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                 | ** ** | **2007**              | ** ** | **2006** | ** ** |
| ** **                                                 | ** ** | **(in thousands)**    | ** ** |
| Proved properties:                                         |       |                  |       |   |   |
| Leasehold  acquisition                                     |       | $                     | 3,095,400  |   | $ | 672,417 |   |
| Development                                                |       | 254,251               |       | 64,785 |   |
| Unproved properties                                        |       | 156,908               |       | 8,624 |   |
| Gas compression plant and pipelines                        |       | 112,182               |       | 20,812 |   |
|                                                       |       | 3,618,741             |       | 766,638 |   |
| Less accumulated depletion, depreciation and  amortization |       | (127,265              | )          | (33,349 | ) |
| Net capitalized  costs                                     |       | $                     | 3,491,476  |   | $ | 733,289 |   |

 

 

85

----

 

**LINN ENERGY, LLC**

**SUPPLEMENTAL OIL AND GAS DATA (Unaudited)****- Continued**

** **

**(C)****                               Resultsof Oil and Gas Producing Activities**

 

The results of operations for oil and gas producing activities(excluding corporate overhead and interest costs) are presented below:

 

| ** **                                                                                                     | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                                     | ** ** | **2007**                         | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                                                                     | ** ** | **(in thousands)**               | ** ** |
| **Revenues:**                                                                                                  | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil, gas and NGL  sales, excluding natural gas marketing revenues                                              |       | $                                | 318,226    |   | $ | 80,393 |   | $ | 44,645 |   |
| Gain (loss) on  oil and gas derivatives                                                                        |       | (345,537                         | )          | 103,308 |   | (76,193 | ) |
| Net oil, gas and  NGL sales                                                                                    |       | (27,311                          | )          | 183,701 |   | (31,548 | ) |
| **Expenses:**                                                                                                  | ** ** | ** **                       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Production costs                                                                                               |       | 88,527                           |       | 18,099 |   | 7,356 |   |
| Depreciation,  depletion and amortization                                                                      |       | 94,127                           |       | 22,714 |   | 7,022 |   |
| Total expenses                                                                                                 |       | 182,654                          |       | 40,813 |   | 14,378 |   |
| Results of operations  for oil and gas producing activities (excluding corporate overhead and  interest costs) |       | $                                | (209,965   | ) | $ | 142,888 |   | $ | (45,926 | ) |

 

Production costs include those costs incurred to operate and maintainproductive wells and related equipment, including such costs as labor, repairs,maintenance, materials, supplies, fuel consumed, insurance and productiontaxes.

 

Depreciation, depletion and amortization expense includes those costsassociated with capitalized acquisition and development costs and supportequipment.  For the years endedDecember 31, 2007 and 2006, depreciation, depletion and amortizationexpense also includes approximately $3.3 million and $1.0 million,respectively, of impairment recorded on oil and gas properties (seeNote 1).

 

There is no tax provision included in the results of oil and gasproducing activities because the Company’s taxable subsidiaries do not own anyof the Company’s oil and gas interests (see Note 15).

 

86

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** **

**LINN ENERGY, LLC**

**SUPPLEMENTAL OIL AND GAS DATA (Unaudited)****- Continued**

 

**(D)****                               NetProved Oil and Gas Reserves**

** **

The proved reserves of oil and gas of the Company have been prepared bythe independent engineering firm DeGolyer and MacNaughton at December 31,2007 and 2006.  The independentengineering firm, Schlumberger Data and Consulting Services, prepared theestimated reserves at December 31, 2005. These reserve estimates have been prepared in compliance with the SECrules based on year-end prices.  An analysisof the change in estimated quantities of oil and gas reserves, all of which arelocated within the United States, is shown below:

 

| ** **                                     | ** ** | **Year Ended December 31, 2007** | ** ** |
|------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                     | ** ** | **Gas (MMcf)**                        | ** ** | **Oil (MBbls)** | ** ** | **NGL (MBbls)** | ** ** | **Total (MMcfe)** | ** ** |
| **Proved developed and undeveloped reserves:** | ** ** | ** **                            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Beginning of year                              |       | 274,006                               |       | 30,010 |   | — |   | 454,066 |   |
| Revisions of previous estimates                |       | (25,418                               | )          | 6,496 |   | 163 |   | 14,531 |   |
| Purchase of minerals in place                  |       | 737,583                               |       | 17,823 |   | 41,741 |   | 1,094,967 |   |
| Sales of minerals in place                     |       | (1,505                                | )          | (1 | ) | — |   | (1,511 | ) |
| Extensions and discoveries                     |       | 71,191                                |       | 1,694 |   | 2,213 |   | 94,633 |   |
| Production                                     |       | (27,001                               | )          | (1,271 | ) | (992 | ) | (40,579 | ) |
| End of year                                    |       | 1,028,856                             |       | 54,751 |   | 43,125 |   | 1,616,107 |   |
| **Proved  developed reserves:**                | ** ** | ** **                            | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Beginning of year                              |       | 166,007                               |       | 24,675 |   | — |   | 314,057 |   |
| End of year                                    |       | 762,115                               |       | 42,791 |   | 25,546 |   | 1,172,142 |   |

 

| ** **                                      | ** ** | **Year Ended December 31, 2006** | ** ** |
|-------------------------------------------------|------------|---------------------------------------|------------|
| ** **                                      | ** ** | **Gas (MMcf)**                        | ** ** | **Oil (MBbls)** | ** ** | **Total (MMcfe)** | ** ** |
| **Proved  developed and undeveloped reserves:** | ** ** | ** **                            | ** ** | ** ** | ** ** | ** ** | ** ** |
| Beginning of  year                              |       | 191,856                               |       | 226 |   | 193,210 |   |
| Revisions of  previous estimates                |       | (37,239                               | )          | 370 |   | (35,018 | ) |
| Purchase of  minerals in place                  |       | 84,951                                |       | 29,784 |   | 263,655 |   |
| Extensions and  discoveries                     |       | 43,037                                |       | — |   | 43,037 |   |
| Production                                      |       | (8,599                                | )          | (370 | ) | (10,818 | ) |
| End of year                                     |       | 274,006                               |       | 30,010 |   | 454,066 |   |
| **Proved developed reserves:**                  | ** ** | ** **                            | ** ** | ** ** | ** ** | ** ** | ** ** |
| Beginning of  year                              |       | 123,865                               |       | 226 |   | 125,220 |   |
| End of year                                     |       | 166,007                               |       | 24,675 |   | 314,057 |   |

 

| ** **                                     | ** ** | **Year Ended   December 31,   2005** | ** ** |
|------------------------------------------------|------------|--------------------------------------|------------|
| ** **                                     | ** ** | **Gas (MMcfe)**                      | ** ** |
| **Proved developed and undeveloped reserves:** | ** ** | ** **                           | ** ** |
| Beginning of  year                             |       | 119,760                              |       |
| Revisions of  previous estimates               |       | 2,415                                |       |
| Purchase of  minerals in place                 |       | 53,976                               |       |
| Extensions and  discoveries                    |       | 21,898                               |       |
| Production                                     |       | (4,839                               | )          |
| End of year                                    |       | 193,210                              |       |
| **Proved developed reserves:**                 | ** ** | ** **                           | ** ** |
| Beginning of  year                             |       | 74,366                               |       |
| End of year                                    |       | 125,220                              |       |

 

87

----

** **

**LINN ENERGY, LLC**

**SUPPLEMENTAL OIL AND GAS DATA (Unaudited)****- Continued**

 

For the years ended December 31, 2007 and 2006the tables above include changes in estimated quantities of oil and NGLreserves shown in Mcf equivalents at a rate of one barrel per six Mcf.  Net oil production included above representsapproximately 3% of total production in 2005.

 

The 14,531 MMcfe positive revision of previous estimates during theyear ended December 31, 2007 was due to a combination of reasons including higheroil and gas prices, higher operating costs, asset performance and changes tofuture scheduled capital projects.  The35,018 MMcfe negative revision of previous estimate during the year endedDecember 31, 2006 was due primarily to a decrease in gas prices.  The 2,415 MMcfe positive revision of previousestimates during the year ended December 31, 2005 was due primarily to anincrease in gas prices.

 

Extensions and discoveries of 94,633 MMcfe, 43,037 MMcfe and 21,898MMcfe during the years ended December 31, 2007, 2006 and 2005, respectively,were primarily due to the drilling of 253 wells during 2007, 159 wells during2006 and 110 wells during 2005, which increased the Company’s proved reserves.

 

The Company made eight, five and three acquisitions of working androyalty interests during the years ended December 31, 2007, 2006 and 2005,respectively, with total proved reserves of 1,094,967 MMcfe, 263,655 MMcfe and53,976 MMcfe, respectively.

 

**(E)****                                 StandardizedMeasure of Discounted Future Net Cash Flows and Changes Therein Relating toProved Reserves**

** **

Information with respect to the standardized measure ofdiscounted future net cash flows relating to proved reserves is summarizedbelow.  Future cash inflows are computedby applying year-end prices relating to the Company’s proved reserves to theyear-end quantities of those reserves. Future production, development, site restoration and abandonment costsare derived based on current costs assuming continuation of existing economic conditions.  There are no future income tax expensesbecause the Company is a non-taxable entity (see Note 15).

 

|                                                                |   | **December 31,** |       |
|---------------------------------------------------------------------|--------|-----------------------|------------|
|                                                                |   | **2007**              | ** ** | **2006** | ** ** | **2005** |   |
|                                                                |   | **(in thousands)**    |       |
|                                                                |   | ** **            |       |
| Future estimated revenues                                           |   | $                     | 13,974,496 |   | $ | 3,053,772 |   | $ | 2,041,930 |   |
| Future estimated production costs                                   |   | (3,482,336            | )          | (868,564 | ) | (332,839 | ) |
| Future estimated development costs                                  |   | (720,170              | )          | (239,328 | ) | (96,542 | ) |
| Future net cash  flows                                              |   | 9,771,990             |       | 1,945,880 |   | 1,612,549 |   |
| 10% annual discount for estimated timing of cash  flows             |   | (6,313,751            | )          | (1,393,620 | ) | (1,060,474 | ) |
| Standardized  measure of discounted future estimated net cash flows |   | $                     | 3,458,239  |   | $ | 552,260 |   | $ | 552,075 |   |

 

| Representative  oil and gas prices at period end: |   |   |   |   |   |   |   |
|---------------------------------------------------|--------|--------|--------|--------|--------|--------|--------|
| Gas – NYMEX per  MMBtu                       |   | $      | 6.80   |   | $      | 5.64   |   | $ | 10.08 |   |
| Oil – NYMEX West  Texas Intermediate per Bbl |   | $      | 95.92  |   | $      | 61.05  |   | $ | 57.98 |   |

 

88

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**LINN ENERGY, LLC**

**SUPPLEMENTAL OIL AND GAS DATA (Unaudited)****- Continued**

 

The following summarizes the principal sources ofchange in the standardized measure of discounted future estimated net cashflows:

 

| ** **                                                           | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                           | ** ** | **2007**                         | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                           | ** ** | **(in thousands)**               | ** ** |
|                                                                 |       |                             |       |   |   |   |   |
| Sales of oil and gas  production, net of production costs            |       | $                                | (229,699   | ) | $ | (62,294 | ) | $ | (37,676 | ) |
| Changes in estimated future development costs                        |       | 5,411                            |       | (2,173 | ) | 55,125 |   |
| Net changes in prices and production costs                           |       | 83,597                           |       | (536,672 | ) | 135,701 |   |
| Purchase and sale of minerals in place                               |       | 2,493,768                        |       | 508,107 |   | 64,361 |   |
| Extensions,  discoveries, and improved recovery, less  related costs |       | 176,693                          |       | 17,872 |   | 192,412 |   |
| Development costs incurred during the period                         |       | 91,273                           |       | 47,112 |   | 26,406 |   |
| Revisions of previous quantity estimates                             |       | 23,481                           |       | (10,747 | ) | 1,026 |   |
| Change in discount                                                   |       | 55,226                           |       | 55,208 |   | 21,503 |   |
| Changes in production rates and other                                |       | 206,229                          |       | (16,228 | ) | (121,817 | ) |
|                                                                 |       | $                                | 2,905,979  |   | $ | 185 |   | $ | 337,041 |   |

 

It is necessary to emphasize that the data presented should not beviewed as representing the expected cash flow from, or current value of,existing proved reserves since the computations are based on a large number ofestimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and theirestimation requires many judgmental determinations and frequent revisions.  The required projection of production andrelated expenditures over time requires further estimates with respect topipeline availability, rates of demand and governmental control.  Actual future prices and costs are likely tobe substantially different from the current prices and costs utilized in thecomputation of reported amounts.  Anyanalysis or evaluation of the reported amounts should give specific recognitionto the computational methods utilized and the limitations inherent therein.

 

 

89

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**LINN ENERGY, LLC**

**SUPPLEMENTAL QUARTERLYDATA (Unaudited)**

** **

**(A)****                               QuarterlyFinancial Data**

 

| ** **                              | ** ** | **Quarters Ended**                          | ** ** |
|-----------------------------------------|------------|---------------------------------------------|------------|
| ** **                              | ** ** | **March 31**                                | ** ** | **June 30** | ** ** | **September 30** | ** ** | **December 31** | ** ** |
| ** **                              | ** ** | **(in thousands, except per unit amounts)** | ** ** |
| **2007**                                | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil, gas and  natural gas liquid sales  |       | $                                           | 39,204     |   | $ | 49,217 |   | $ | 75,062 |   | $ | 154,743 |   |
| Gain (loss) on  oil and gas derivatives |       | (60,441                                     | )          | (17,707 | ) | (65,440 | ) | (201,949 | ) |
| Total revenues                          |       | (17,369                                     | )          | 33,788 |   | 18,479 |   | (42,135 | ) |
| Total expenses (1)                      |       | 36,275                                      |       | 41,068 |   | 72,194 |   | 109,969 |   |
|                                    |       |                                        |       |   |   |   |   |   |   |
| Net loss                                |       | $                                           | (67,847    | ) | $ | (17,126 | ) | $ | (76,222 | ) | $ | (203,154 | ) |
|                                    |       |                                        |       |   |   |   |   |   |   |
| **Net loss per unit:**                  | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Units – basic                      |       | $                                           | (1.35      | ) | $ | (0.29 | ) | $ | (0.94 | ) | $ | (2.01 | ) |
| Units – diluted                    |       | $                                           | (1.35      | ) | $ | (0.29 | ) | $ | (0.94 | ) | $ | (2.01 | ) |

 

| ** **                       | ** ** | **Quarters Ended**                          | ** ** |
|----------------------------------|------------|---------------------------------------------|------------|
| ** **                       | ** ** | **March 31**                                | ** ** | **June 30** | ** ** | **September 30** | ** ** | **December 31** | ** ** |
| ** **                       | ** ** | **(in thousands, except per unit amounts)** | ** ** |
| **2006**                         | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil and gas  sales               |       | $                                           | 16,375     |   | $ | 13,529 |   | $ | 23,506 |   | $ | 26,983 |   |
| Gain on oil and  gas derivatives |       | 24,246                                      |       | 12,895 |   | 57,396 |   | 8,771 |   |
| Total revenues                   |       | 42,128                                      |       | 27,974 |   | 82,257 |   | 38,699 |   |
| Total expenses (1)               |       | 17,147                                      |       | 15,166 |   | 17,989 |   | 36,825 |   |
|                             |       |                                        |       |   |   |   |   |   |   |
| Net income  (loss)               |       | $                                           | 21,977     |   | $ | 10,239 |   | $ | 53,057 |   | $ | (6,088 | ) |
|                             |       |                                        |       |   |   |   |   |   |   |
| **Net income (loss) per unit:**  | ** ** | ** **                                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Units – basic               |       | $                                           | 0.84       |   | $ | 0.37 |   | $ | 1.92 |   | $ | (0.16 | ) |
| Units – diluted             |       | $                                           | 0.84       |   | $ | 0.36 |   | $ | 1.89 |   | $ | (0.16 | ) |

----

(1)              Includes operating, natural gasmarketing, general and administrative, data license expenses and depreciation,depletion and amortization.

 

 

90

----

 

**Item 9.     ****Changes in and Disagreements WithAccountants on Accounting and Financial Disclosure**

 

None.

 

**Item 9A.  ****Controls and Procedures**

** **

***Evaluation of Disclosure Controls and Procedures***

*** ***

TheCompany maintains disclosure controls and procedures that are designed toensure that information required to be disclosed in the Company’s reports underthe Securities Exchange Act of 1934, as amended (the “Exchange Act”) isrecorded, processed, summarized and reported within the time periods specifiedin the SEC’s rules and forms, and that such information is accumulated andcommunicated to management, including the Company’s Chief Executive Officer andChief Financial Officer, and the Company’s Audit Committee of the Board of Directors,as appropriate, to allow timely decisions regarding required disclosure.  In designing and evaluating the disclosurecontrols and procedures, management recognizes that any controls andprocedures, no matter how well designed and operated, can provide onlyreasonable assurance of achieving the desired control objectives, andmanagement is required to apply its judgment in evaluating the cost-benefitrelationship of possible controls and procedures.

 

TheCompany carried out an evaluation under the supervision and with theparticipation of its management, including its Chief Executive Officer andChief Financial Officer, of the effectiveness of its disclosure controls andprocedures as of the end of the period covered by this report.  Based on this evaluation, the Chief ExecutiveOfficer and Chief Financial Officer concluded that the Company’s disclosurecontrols and procedures were effective as of December 31, 2007.

 

***Management’s Annual Report on Internal Control OverFinancial Reporting***

*** ***

SeeManagement’s Report on Internal Control Over Financial Reporting underItem 8 of this Form 10-K.

 

***Changes in the Company’s Internal Control Over FinancialReporting***

*** ***

TheCompany’s management is also responsible for establishing and maintainingadequate internal controls over financial reporting, as defined inRules 13a-15(f) and 15d-15(f) of the Exchange Act.  The Company’s internal controls were designedto provide reasonable assurance as to the reliability of its financialreporting and the preparation and presentation of the consolidated financialstatements for external purposes in accordance with accounting principlesgenerally accepted in the United States.

 

Becauseof its inherent limitations, internal control over financial reporting may notdetect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods aresubject to the risk that controls may become inadequate because of changes inconditions, or that the degree of compliance with the policies or proceduresmay deteriorate.

 

Exceptfor the potential changes noted in the following paragraph relating to theacquisition of certain oil and gas properties during 2007, there were nochanges in the Company’s internal controls over financial reporting during thefourth quarter of 2007 that materially affected, or were reasonably likely tomaterially affect, the Company’s internal control over financial reporting.

 

TheCompany completed an acquisition of oil and gas properties in the Mid-Continentin August 2007.  Company managementcontinues to integrate internal controls and enhanced reporting related to thefinancial performance of the acquired operations with the Company’s internalcontrol over financial reporting.  Thisintegration may lead to changes in these controls in future fiscal periods, butmanagement does not yet know whether these changes will materially affect theCompany’s internal control over financial reporting.  Management expects the integration process tobe completed during 2008.

 

**Item 9B.   Other Information**

** **

None.

 

 

91

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** **

**Part III**

** **

**Item 10.   Directors,Executive Officers and Corporate Governance**

** **

Alist of the Company’s executive officers and biographical information appearsin Part I. Item 1. “Business and Properties” in this Form 10-K.  Information about Company Directors may befound under the caption “Election of Directors” of the Proxy Statement for theAnnual Meeting of Unitholders to be held on May 29, 2008 (the “2008 ProxyStatement”).  That information is incorporatedherein by reference.

 

Theinformation in the 2008 Proxy Statement set forth under the caption “Section16(a) Beneficial Ownership Reporting Compliance” is incorporated herein byreference.

 

The information required by this item regarding audit committeerelated matters, codes of ethics and committee charters is incorporated byreference from the 2008 Proxy Statement under the caption “CorporateGovernance.”

 

**Item 11.   ExecutiveCompensation**

** **

Information required bythis item is incorporated herein by reference to the 2008 Proxy Statement.

 

**Item 12.****          Security Ownership ofCertain Beneficial Owners and Management and Related Stockholder Matters**

** **

Information required bythis item is incorporated herein by reference to the 2008 Proxy Statement.

 

**SecuritiesAuthorized for Issuance Under Equity Compensation Plans**

** **

Thefollowing summarizes information regarding the number of units that areavailable for issuance under all of the Company’s equity compensation plans asof December 31, 2007:

 
| **Plan Category**                                           | ** ** | **Number of Securities to be  Issued Upon Exercise of  Outstanding Unit Options,  Warrants and Rights****(1)** | ** ** | **Weighted-Average Exercise  Price of Outstanding Unit  Options, Warrants  and Rights** | ** ** | **Number of Securities  Remaining Available for  Future Issuance Under  Equity Compensation Plans  (Excluding Securities  Reflected in Column (a))** | ** ** |
|-------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------|------------|
| ** **                                                  | ** ** | **(a)**                                                                                                        | ** ** | **(b)**                                                                                 | ** ** | **(c)**                                                                                                                                              | ** ** |
| Equity compensation  plans approved by security holders     |       | 1,077,021                                                                                                      |       | $25.36                                                                                  |       | 916,572                                                                                                                                              |       |
| Equity compensation  plans not approved by security holders |       | —                                                                                                         |       | —                                                                                  |       | —                                                                                                                                               |       |
| Total                                                       |       | 1,077,021                                                                                                      |       | $25.36                                                                                  |       | 916,572                                                                                                                                              |       |

----

(1)              Includes 80,000 unit options awardedunder employment agreements for which the grant date for expense recognitionoccurred in January 2008.

 

**Item 13.   CertainRelationships and Related Transactions, and Director Independence**

** **

Information required bythis item is incorporated herein by reference to the 2008 Proxy Statement.

 

**Item 14.   PrincipalAccounting Fees and Services**

** **

Information required bythis item is incorporated herein by reference to the 2008 Proxy Statement.

 

 

92

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**Part IV**

** **

**Item 15.   Exhibitsand Financial Statement Schedules**

** **

(a) - 2.  Financial and Statement Schedules:

 

All schedules are omittedfor the reason that they are not required or the information is otherwisesupplied under Part II. Item 8. “Financial Statements and SupplementaryData.”

 

(a) - 3.  Exhibits Filed:

 

Theexhibits required to be filed by this item are set forth in the Index toExhibits accompanying this report.

 

93

----

 

**SIGNATURES**

** **

Pursuant to therequirements of the Securities Exchange Act of 1934, the Registrant has dulycaused this report to be signed on its behalf by the undersigned thereunto dulyauthorized.

 
|                     | LINN  ENERGY, LLC |
|--------------------------|-------------------|
|                     |              |
|                     |              |
| Date:  February 28, 2008 | By:               | /s/  MICHAEL C. LINN |
|                     |              | Michael  C. Linn |
|                     | * *          | *Chairman and Chief Executive Officer* |
|                     | * *          | * * |
|                     | * *          | * * |
|                     | * *          | * * |
| Date:  February 28, 2008 | By:               | /s/  LISA D. ANDERSON |
|                     |              | Lisa  D. Anderson |
|                     | * *          | *Senior Vice President and Chief Accounting Officer* |

 

Pursuantto the requirements of the Securities Exchange Act of 1934, this Annual Reporthas been signed below by the following persons on behalf of the Registrant andin the capacities and on the dates indicated.

 
| **Signature**                 | ** ** | **Title**                                            | ** ** | **Date**                |
|-------------------------------|------------|------------------------------------------------------|------------|-------------------------|
|                          |       |                                                 |       |                    |
| /s/ MICHAEL C. LINN           |       | Chairman and Chief Executive Officer                 |       | February  28, 2008 |
| Michael C. Linn               |       | (Principal Executive Officer)                        |       |                    |
|                          |       |                                                 |       |                    |
| /s/ KOLJA ROCKOV              |       | Executive Vice President and Chief Financial Officer |       | February 28, 2008  |
| Kolja Rockov                  |       | (Principal Financial Officer)                        |       |                    |
|                          |       |                                                 |       |                    |
| /s/ LISA D. ANDERSON          |       | Senior Vice President and Chief Accounting Officer   |       | February 28, 2008  |
| Lisa D. Anderson              |       | (Principal Accounting Officer)                       |       |                    |
|                          |       |                                                 |       |                    |
| /s/ GEORGE A. ALCORN          |       | Independent Director                                 |       | February 28, 2008  |
| George A. Alcorn              |       |                                                 |       |                    |
|                          |       |                                                 |       |                    |
| /s/ TERRENCE S. JACOBS        |       | Independent Director                                 |       | February 28, 2008  |
| Terrence S. Jacobs            |       |                                                 |       |                    |
|                          |       |                                                 |       |                    |
| /s/ JOSEPH P. McCOY           |       | Independent Director                                 |       | February 28, 2008  |
| Joseph P. McCoy               |       |                                                 |       |                    |
|                          |       |                                                 |       |                    |
| /s/ JEFFREY C. SWOVELAND |       | Independent Director                                 |       | February 28, 2008  |
| Jeffrey C. Swoveland          |       |                                                 |       |                    |

 

 

94

----

 

**INDEX TO EXHIBITS**

 
| **Exhibit Number** | ** ** | ** ** | ** ** | **Description** |
|--------------------|------------|------------|------------|-----------------|
| 2.                 | 1†    |       | —     |            | Purchase and Sale  Agreement, dated December 20, 2007, between Lamamco Drilling Company, as  Seller and Linn Energy Holdings, LLC, as Purchaser |
| 2.                 | 2†    |       | —     |            | Amendment to Purchase  and Sale Agreement, dated as of January 31, 2008, between Lamamco Drilling  Company, as Seller and Linn Energy Holdings, LLC, as Purchaser |
| 2.                 | 3          |       | —     |            | Amended and Restated  Mid-Continent Onshore Package Purchase Agreement, dated August 30, 2007,  between Dominion Exploration & Production, Inc., Dominion Oklahoma  Texas Exploration & Production, Inc., LDNG Texas Holdings, LLC, and  DEPI Texas Holdings, LLC, as Sellers, and Linn Energy, LLC, as Purchaser  (incorporated herein by reference to Exhibit 2.1 to Current Report on  Form 8-K filed on September 5, 2007) |
| 3.                 | 1          |       | —     |            | Certificate of  Formation of Linn Energy Holdings, LLC (now Linn Energy, LLC) (incorporated  herein by reference to Exhibit 3.1 to Registration Statement on  Form S-1 (File No. 333-125501) filed by Linn Energy, LLC on  June 3, 2005) |
| 3.                 | 2          |       | —     |            | Certificate of  Amendment to Certificate of Formation of Linn Energy Holdings, LLC (now Linn  Energy, LLC) (incorporated herein by reference to Exhibit 3.2 to  Registration Statement on Form S-1 (File No. 333-125501) filed by  Linn Energy, LLC on June 3, 2005) |
| 3.                 | 3          |       | —     |            | Second Amended and  Restated Limited Liability Company Agreement of Linn Energy, LLC dated  January 19, 2006 (incorporated herein by reference to Exhibit 3.3  to Annual Report on Form 10-K for the year ended December 31, 2006,  filed on March 30, 2007) |
| 3.                 | 4          |       | —     |            | Amendment No. 1 to  Second Amended and Restated Limited Liability Company Agreement of Linn  Energy, LLC dated October 24, 2006 (incorporated herein by reference to  Exhibit 3.4 to Annual Report on Form 10-K for the year ended  December 31, 2006, filed on March 30, 2007) |
| 3.                 | 5          |       | —     |            | Amendment No. 2 to  Second Amended and Restated Limited Liability Company Agreement of Linn  Energy, LLC dated February 1, 2007 (incorporated herein by reference to  Exhibit 3.5 to Annual Report on Form 10-K for the year ended  December 31, 2006, filed on March 30, 2007) |
| 3.                 | 6          |       | —     |            | Amendment No. 3 to  Second Amended and Restated Limited Liability Company Agreement of Linn  Energy, LLC dated August 31, 2007 (incorporated herein by reference to  Exhibit 4.1 to Current Report on Form 8-K, filed on  September 5, 2007) |
| 4.                 | 1          |       | —     |            | Form of specimen unit  certificate for the units of Linn Energy, LLC (incorporated herein by  reference to Exhibit 4.1 to the Annual Report on Form 10-K for the  year ended December 31, 2005, filed on May 31, 2006) |
| 10.                | 1*         |       | —     |            | Form of Linn Energy,  LLC Long-Term Incentive Plan (incorporated herein by reference to  Exhibit 10.10 to Amendment No. 4 to Registration Statement on  Form S-1 filed on December 14, 2005) |
| 10.                | 2*         |       | —     |            | First Amendment to Linn  Energy, LLC Long-Term Incentive Plan dated January 18, 2007  (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K  filed on January 19, 2007) |
| 10.                | 3*         |       | —     |            | Second Amendment to  Linn Energy, LLC Long-Term Incentive Plan dated March 21, 2007  (incorporated herein by reference to Exhibit 10.3 to Annual Report on Form 10-K  for the year ended December 31, 2006, filed on March 30, 2007) |
| 10.                | 4†    |       | —     |            | Form of Executive Unit  Option Agreement pursuant to the Linn Energy, LLC Long-Term Incentive Plan |
| 10.                | 5†    |       | —     |            | Form of Executive  Restricted Unit Agreement pursuant to the Linn Energy, LLC Long-Term  Incentive Plan |
| 10.                | 6*         |       | —     |            | Form of Phantom Unit  Grant Agreement for Independent Directors pursuant to the Linn Energy, LLC  Long-Term Incentive Plan (incorporated herein by reference to  Exhibit 10.1 to Current Report on Form 8-K filed on August 9,  2006) |
| 10.                | 7*         |       | —     |            | Amended and Restated  Employment Agreement, dated effective as of December 14, 2005 between  Linn Operating, Inc. and Michael C. Linn (incorporated herein by  reference to Exhibit 10.12 to Amendment No. 4 to Registration  Statement on Form S-1 (File No. 333-125501) filed on  December 14, 2005) |

 

95

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| **Exhibit Number** | ** ** | ** ** | ** ** | **Description** |
|--------------------|------------|------------|------------|-----------------|
| 10.                | 8*         |       | —     |            | Second Amended and  Restated Employment Agreement, dated as of September 15, 2005 between  Linn Operating, Inc. and Kolja Rockov (incorporated herein by reference to  Exhibit 10.12 to Amendment No. 2 to Registration Statement on  Form S-1 (File No. 333-125501) filed on October 31, 2005) |
| 10.                | 9*         |       | —     |            | Employment Agreement,  dated effective as of December 18, 2006 between Linn Operating, Inc. and  Mark E. Ellis (incorporated herein by reference to Exhibit 10.1 to  Current Report on Form 8-K filed on November 29, 2006) |
| 10.                | 10*        |       | —     |            | Employment Agreement,  dated effective as of April 3, 2006 between Linn Operating, Inc. and  Thomas A. Lopus (incorporated herein by reference to Exhibit 10.1  to Current Report on Form 8-K filed on April 18, 2006) |
| 10.                | 11*        |       | —     |            | Employment Agreement,  dated effective as of July 7, 2006 between Linn Operating, Inc. and Lisa  D. Anderson (incorporated herein by reference to Exhibit 10.1 to Current  Report on Form 8-K filed on July 13, 2006) |
| 10.                | 12*†  |       | —     |            | Employment Agreement,  dated effective March 22, 2007 between Linn Operating, Inc. and  Charlene A. Ripley |
| 10.                | 13*†  |       | —     |            | Employment Agreement, dated  effective February 7, 2007 between Linn Operating, Inc. and  Arden L. Walker, Jr. |
| 10.                | 14         |       | —     |            | Third Amended and  Restated Credit Agreement dated as of August 31, 2007 among Linn Energy,  LLC as Borrower, BNP Paribas, as Administrative Agent, and the Lenders and  agents Party thereto (incorporated herein by reference to Exhibit 10.1  to Current Report on Form 8-K filed on September 5, 2007) |
| 10.                | 15†   |       | —     |            | First Amendment, dated  November 2, 2007, to Third Amended and Restated Credit Agreement among  Linn Energy, LLC, as borrower, BNP Paribas, as administrative agent, and the  lenders and agents party thereto |
| 10.                | 16†   |       | —     |            | Second  Amendment, dated January 31, 2008, to Third Amended and Restated Credit  Agreement among Linn Energy, LLC, as borrower, BNP Paribas, as administrative  agent, and the lenders and agents party thereto |
| 10.                | 17         |       | —     |            | Third Amended and  Restated Guaranty and Pledge Agreement dated as of August 31, 2007 made  by Linn Energy, LLC and each of the other Obligors in favor of BNP Paribas,  as Administrative Agent (incorporated herein by reference to  Exhibit 10.2 to Current Report on Form 8-K filed on  September 5, 2007) |
| 10.                | 18†   |       | —     |            | Second Lien Term Loan  Agreement dated as of January 31, 2008 among Linn Energy, LLC as  Borrower, BNP Paribas, as Administrative Agent, and the lenders and agents  party thereto |
| 10.                | 19†   |       | —     |            | Second Lien Guaranty  and Pledge Agreement dated as of January 31, 2008 made by Linn Energy,  LLC and each of the other Obligors in favor of BNP Paribas, as Administrative  Agent |
| 10.                | 20         |       | —     |            | Class B Unit and  Unit Purchase Agreement, dated as of October 24, 2006 by and between  Linn Energy, LLC and the Purchasers named therein (incorporated herein by  reference to Exhibit 10.1 to Current Report on Form 8-K filed on  October 25, 2006) |
| 10.                | 21         |       | —     |            | Registration Rights  Agreement dated as of October 24, 2006 by and among Linn Energy, LLC and  the Purchasers named therein (incorporated herein by reference to  Exhibit 10.2 to Current Report on Form 8-K filed on  October 25, 2006) |
| 10.                | 22         |       | —     |            | Class C Unit and  Unit Purchase Agreement, dated as of February 1, 2007 by and among the  Company and the Purchasers named therein (incorporated herein by reference to  Exhibit 10.1 to Current Report on Form 8-K filed on  February 5, 2007) |
| 10.                | 23         |       | —     |            | Registration Rights  Agreement dated February 1, 2007, by and among the Company and the  Purchasers named therein (incorporated herein by reference to  Exhibit 10.2 to Current Report on Form 8-K filed on  February 5, 2007) |
| 10.                | 24         |       | —     |            | Class D Unit and  Unit Purchase Agreement, dated as of June 29, 2007 by and among the  Company and the Purchasers named therein (incorporated herein by reference to  Exhibit 10.17 to Quarterly Report on Form 10-Q for the quarter  ended June 30, 2007, filed on August 14, 2007) |

 

96

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| **Exhibit Number** | ** ** | ** ** | ** ** | **Description** |
|--------------------|------------|------------|------------|-----------------|
| 10.                | 25         |       | —     |            | Registration Rights  Agreement dated August 31, 2007, by and among the Company and the  Purchasers named therein (incorporated herein by reference to  Exhibit 10.3 to Current Report on Form 8-K filed on September 5,  2007) |
| 21.                | 1†    |       | —     |            | Significant  Subsidiaries of Linn Energy, LLC |
| 23.                | 1†    |       | —     |            | Consent of KPMG LLP for  Linn Energy, LLC |
| 23.                | 2†    |       | —     |            | Consent of DeGolyer and  MacNaughton Data and Consulting Services |
| 23.                | 3†    |       | —     |            | Consent of Schlumberger  Technology Corporation |
| 31.                | 1†    |       | —     |            | Section 302  Certification of Michael C. Linn, Chairman and Chief Executive Officer of  Linn Energy, LLC |
| 31.                | 2†    |       | —     |            | Section 302  Certification of Kolja Rockov, Executive Vice President and Chief Financial  Officer of Linn Energy, LLC |
| 32.                | 1†    |       | —     |            | Section 906  Certification of Michael C. Linn, Chairman and Chief Executive Officer of  Linn Energy, LLC |
| 32.                | 2†    |       | —     |            | Section 906  Certification of Kolja Rockov, Executive Vice President and Chief Financial  Officer of Linn Energy, LLC |

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†  Filed herewith.

 

*  Management Contract or Compensatory Plan orArrangement required to be filed as an exhibit hereto pursuant to Item 601of Regulation S-K.

 

97

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